e424b4

Filed Pursuant to Rule 424(b)(4)
Registration No. 333-165212

PROSPECTUS

42,000,000 Shares

Oasis Petroleum Inc.

COMMON STOCK

Oasis Petroleum Inc. is offering 30,370,000 shares of its common stock and the selling stockholder is offering 11,630,000 shares of common stock. We will not receive any proceeds from the sale of shares by the selling stockholder. This is our initial public offering and no public market currently exists for our shares.

Our common stock has been approved for listing on the New York Stock Exchange under the symbol “OAS.”

Investing in our common stock involves risks. See “Risk Factors” beginning on page 15.

Price $14.00 Per Share


			Underwriting				Proceeds to
	Price to		Discounts and		Proceeds to		Selling
	Public		Commissions(1)		Company		Stockholder

Per Share	$	14.00	$	0.84	$	13.16	$	13.16
Total	$	588,000,000	$	35,280,000	$	399,669,200	$	153,050,800


(1)		See “Underwriters — Relationship with Underwriters” for additional items of underwriting compensation.

The selling stockholder has granted the underwriters the right to purchase up to an additional 6,300,000 shares of common stock to cover over-allotments.

The Securities and Exchange Commission and state securities regulators have not approved or disapproved of these securities, or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares of common stock to purchasers on June 22, 2010.


Morgan Stanley	UBS Investment Bank

Simmons & Company International


J.P. Morgan	Tudor, Pickering, Holt & Co.	Wells Fargo Securities

BNP PARIBAS

Canaccord Genuity

Johnson Rice & Company L.L.C.

Morgan Keegan & Company, Inc.

Raymond James

RBC Capital Markets

Scotia Capital

June 16, 2010

TABLE OF CONTENTS


Prospectus Summary			1
The Offering			8
Risk Factors			15
Cautionary Note Regarding Forward-Looking Statements			36
Use of Proceeds			37
Dividend Policy			37
Capitalization			38
Dilution			39
Selected Historical Consolidated and Unaudited Pro Forma Financial Data			40
Management’s Discussion and Analysis of Financial Condition and Results of Operations			42
Business			66
Management			92
Executive Compensation and Other Information			98
Certain Relationships and Related Party Transactions			116
Corporate Reorganization			118
Principal and Selling Stockholders			120
Description of Capital Stock			122
Shares Eligible for Future Sale			126
Material U.S. Federal Income and Estate Tax Considerations to Non-U.S. Holders			128
Underwriters			131
Legal Matters			138
Experts			138
Where You Can Find More Information			139
Index to Financial Statements			F-1
Glossary of Oil and Natural Gas Terms			A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or to which we have referred you. Neither we nor the selling stockholder has authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We and the selling stockholder are offering to sell shares of common stock and seeking offers to buy shares of common stock, only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock.

Until July 11, 2010, all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and unaudited pro forma financial information and related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ option to purchase additional common shares is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and the “company” refer to Oasis Petroleum LLC and its subsidiaries before the completion of our corporate reorganization and Oasis Petroleum Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter.

OASIS PETROLEUM INC.

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources. We have accumulated approximately 292,000 net leasehold acres in the Williston Basin, approximately 85% of which are undeveloped. We are currently focused on exploiting what we have identified as significant resource potential from the Bakken and Three Forks formations, which are present across a substantial majority of our acreage. A report issued by the United States Geologic Survey, or USGS, in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States. We believe the location, size and concentration of our acreage creates an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial experience in the Williston Basin. We have built our leasehold acreage position in the Williston Basin primarily through acquisitions in our three primary project areas, West Williston, East Nesson and Sanish. For a description of our acquisition activity, please see “—Our Acquisition History” below.

DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 13.3 MMBoe as of December 31, 2009, 42% of which were classified as proved developed and 93% of which were comprised of oil. The following table presents summary data for each of our primary project areas as of December 31, 2009 unless otherwise indicated:


							2010 Budget										Average
			Identified Drilling								Drilling		Estimated Net				Daily
	Net		Locations				Gross		Net		Capex		Proved Reserves				Production
	Acreage		Gross		Net		Wells		Wells		(In millions)		MMBoe		% Developed		(Boe/d)(1)

Williston Basin
West Williston(2)		159,491		268		106.5		41		18.8	$	110		5.0		55%		1,078
East Nesson(2)		124,004		113		57.0		13		7.4		47		3.9		36%		1,037
Sanish(3)		8,747		88		9.6		37		3.8		22		4.3		32%		1,084

Total Williston Basin		292,242		469		173.1		91		30.0		179		13.2		42%		3,199
Other		879		—		—		—		—		—		0.1		100%		96

Total		293,121		469		173.1		91		30.0	$	179		13.3		42%		3,295


(1)		Represents average daily production for the three months ended March 31, 2010.


(2)		Identified gross and net drilling locations in our West Williston and East Nesson project areas are primarily comprised of Bakken wells based on 1,280-acre spacing and do not include any infill wells targeting the Bakken formation or any primary or infill wells targeting the Three Forks formation.

(3)		Identified gross and net drilling locations in our Sanish project area include a single Bakken infill well per 1,280-acre or 640-acre spacing unit (excluding spacing units already containing two Bakken producing wells) and include 10 gross (1.6 net) primary wells targeting the Three Forks formation.

In our West Williston and East Nesson project areas, we have an inventory of approximately 381 gross primary drilling locations (23 of which are proved undeveloped), substantially all of which are on 1,280-acre spacing targeting the Bakken formation. We plan to aggressively develop these specifically identified drilling locations using horizontal drilling and multi-stage fracture stimulation techniques. In our Sanish project area, we have an additional 88 gross non-operated drilling locations (63 of which are proved undeveloped). A single additional infill well per spacing unit targeting the Bakken formation across all three of our Williston Basin project areas would add over 500 incremental potential drilling locations. We are also evaluating the resource potential in the Three Forks formation across our leasehold position and believe there may be a significant number of additional potential drilling locations targeting this formation. We believe we have a total of 2,188 gross (859.9 net) potential additional drilling locations in the Williston Basin assuming up to a total of three Bakken and three Three Forks locations per spacing unit.

Our total 2010 capital expenditure budget is $220 million, which consists of:


	•	$134 million for drilling and completing operated wells;

	•	$45 million for drilling and completing non-operated wells;

	•	$15 million for maintaining and expanding our leasehold position;

	•	$5 million for constructing infrastructure to support production in our core project areas; and

	•	$21 million in unallocated funds which are available for additional drilling and leasing costs and activity.

While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Our Acquisition History

We built our leasehold position in our West Williston, East Nesson and Sanish project areas through the following acquisitions and development activities:


	•	In June 2007, we acquired approximately 175,000 net leasehold acres in the Williston Basin with then-current net production of approximately 1,000 Boe/d. This acreage is the core of our West Williston project area.

	•	In May 2008, we entered into a farm-in and purchase arrangement, under which we earned or acquired approximately 48,000 net leasehold acres, establishing our initial position in the East Nesson project area.

	•	In June 2009, we acquired approximately 37,000 net leasehold acres with then-current net production of approximately 800 Boe/d, approximately 92% of which was from the Williston Basin. This acquisition consolidated our acreage in the East Nesson project area and established our Sanish project area.

	•	In September 2009, we acquired an additional 46,000 net leasehold acres with then-current net production of approximately 300 Boe/d. This acquisition further consolidated our acreage in the East Nesson project area.

Our Business Strategy

Our goal is to increase stockholder value by building reserves, production and cash flows at an attractive return on invested capital. We seek to achieve our goals through the following strategies:


	•	Aggressively Develop our Williston Basin Leasehold Position. We intend to aggressively drill and develop our acreage position to maximize the value of our resource potential. The aggregate 469 gross drilling locations that we have specifically identified in the Bakken formation in our three project areas will be our primary targets in the near term. Our 2010 drilling plan contemplates drilling approximately 35 gross (22.4 net) operated wells in these project areas by using two operated drilling rigs for the full year and adding up to three additional drilling rigs later in the year. Subject to market conditions and rig availability, we expect to operate up to seven drilling rigs in 2011, which could enable us to drill as many as 60 gross operated wells during that year. We believe we have the ability to add additional rigs this year if market conditions and program results warrant.

	•	Enhance Returns by Focusing on Operational and Cost Efficiencies. Our management team is focused on continuous improvement of our operating measures and has significant experience in successfully converting early-stage resource opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our project areas provides us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and fluid handling facilities and reducing the time and cost of rig mobilization.

	•	Adopt and Employ Leading Drilling and Completion Techniques. Our team is focused on enhancing our drilling and completion techniques to maximize recovery. We believe these techniques have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of techniques such as using longer laterals and more tightly spaced fracturing stimulation stages. We continuously evaluate our internal drilling results and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to evolve. This continued evolution may significantly enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.

	•	Pursue Strategic Acquisitions with Significant Resource Potential. In the near term, we intend to identify and acquire additional acreage and producing assets in the Williston Basin to supplement our existing operations. Going forward, we expect to selectively target additional domestic basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin. While we have no current intention to pursue international opportunities, our management team has significant international acquisition and operating expertise. If we identify an international opportunity with appropriate scale, risk and resource conversion potential, our board of directors may approve such an investment should they determine it is in the long-term best interest of our stockholders to do so.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:


	•	Substantial Leasehold Position in one of North America’s Leading Unconventional Oil-Resource Plays. Our current leasehold position of approximately 292,000 net leasehold acres in the Williston Basin is highly prospective in the Bakken formation. We believe our acreage is one of the largest concentrated leasehold positions in the basin prospective in the Bakken formation, and much of our acreage is in areas of significant drilling activity by other exploration and production companies. While we are initially targeting the Bakken formation, we are also evaluating what we believe to be significant prospectivity in the Three Forks formation which underlies a large portion of our acreage. We expect that the scale and concentration of our acreage will enable us to continue to improve our drilling and completion costs and operational efficiency.


	•	Large, Multi-Year Project Inventory. We have an inventory of approximately 469 gross drilling locations, primarily targeting the Bakken formation. We plan to drill 35 gross (22.4 net) operated wells across our West Williston and East Nesson project areas in 2010, the completion of which would represent 14% of our 246 gross identified operated drilling locations in these two project areas. We may be able to enhance the total recovery from the Bakken formation by drilling potential infill locations. In addition, our total number of drilling locations may also be substantially increased by pursuing the prospectivity we have identified in the Three Forks formation.

	•	Management Team with Proven Acquisition and Operating Skills. Our senior management team has extensive expertise in the oil and gas industry as previous members of management at Burlington Resources. The senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in other North American and international basins. See “Business — Our Operations — Management Experience with Resource Conversion Plays and Horizontal Drilling Techniques.” We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, this team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs, and also has prior experience in the Williston Basin.

	•	Incentivized Management Team. Our management team will own a significant direct ownership interest in us immediately following the completion of this offering. In addition, our management team will also initially own an additional approximate 11% indirect economic interest in us through our controlling stockholder, OAS Holding Company LLC, or OAS Holdco, which will initially own approximately 51% of our outstanding shares of common stock (or 45% if the underwriters’ over-allotment option is exercised in full) based on the initial public offering price of $14.00 per share. Our management team may significantly increase its sharing percentage in the shares held by OAS Holdco by increasing the return on investment for the other members of OAS Holdco. We believe our management team’s direct ownership interest immediately following the offering as well as their ability to increase their interest over time through OAS Holdco provides significant incentives to grow the value of our business for the benefit of all stockholders. See “Corporate Reorganization — LLC Agreement of OAS Holdco.”

	•	Operating Control over the Majority of our Portfolio. In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. We expect to operate 52% of our 469 identified gross drilling locations, or 83% of our 173.1 identified net drilling locations. As of December 31, 2009, approximately 59% of our total proved reserves were attributable to properties that we expect to operate. Approximately 75% of our estimated 2010 drilling and completion capital expenditure budget is related to operated wells, which we anticipate will result in an increase in 2010 of the percentage of our proved reserves attributable to properties we expect to operate. As of December 31, 2009, our average working interest in our operated and non-operated identified drilling locations was 58% and 14%, respectively. Controlling operations will allow us to dictate the pace of development as well as the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques.

Recent Developments

Drilling Activity as of May 31, 2010. Since December 31, 2009, we have drilled nine gross (7.4 net) operated wells in the Bakken formation. Seven of these wells are on production, and two wells are being completed. Additionally, we have two operated drilling rigs in the West Williston project area and two in the East Nesson project area, each of which is drilling a well targeting the Bakken formation. All of the 16 gross (1.6 net) non-operated wells in progress on December 31, 2009 have initiated production. Subsequent to December 31, 2009, an additional 37 gross (3.2 net) non-operated wells have begun operations with 18 gross wells on production and 19 gross wells being drilled or completed.

We had average daily production of 3,295 Boe per day during the three months ended March 31, 2010. Approximately 3,199 Boe per day, or 97% of the total, was produced from Williston Basin properties.

During the one month ended April 30, 2010, we had average daily production of 4,044 Boe per day.

Amended and Restated Credit Facility. On February 26, 2010, we entered into an amended and restated revolving credit facility, which will have a borrowing base of $70 million upon completion of this offering. Our revolving credit facility matures on February 26, 2014. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Reserve-based credit facility.” As of June 16, 2010, we had $75.0 million of indebtedness outstanding under our revolving credit facility. We anticipate that a portion of the net proceeds from this offering will be used to repay all of our borrowings outstanding as of the closing.

Marketing and Transportation

The Williston Basin crude oil transportation and refining infrastructure has grown substantially in recent years, largely in response to drilling activity in the Bakken formation. As of April 30, 2010, there was approximately 394,600 barrels per day of crude oil transportation and refining capacity in the Williston Basin, comprised of approximately 276,600 barrels per day of pipeline transportation capacity and approximately 58,000 barrels per day of refining capacity at the Tesoro Corporation Mandan refinery. In addition, approximately 60,000 barrels per day of specifically dedicated railcar transportation capacity has recently been placed into service in the Williston Basin. Based on publicly announced expansion projects, pipeline transportation capacity for Williston Basin oil production could increase by 30,000 to 115,000 barrels per day by 2013, and we believe additional projects are under consideration. We sell a substantial majority of our oil production directly at the wellhead and are not responsible for its transportation. However, the price we receive at the wellhead is impacted by transportation and refining infrastructure constraints. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Risk Factors — Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.”

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. In particular, the following considerations may offset our competitive strengths or have a negative effect on our business strategy as well as on activities on our properties, which could cause a decrease in the price of our common stock and result in a loss of all or a portion of your investment:


	•	A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

	•	Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

	•	Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

	•	Our business is difficult to evaluate because we have a limited operating history.

	•	Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.

	•	Substantially all of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.

	•	The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.


	•	We expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, would qualify for and will rely on exemptions from certain corporate governance requirements.

For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see “Risk Factors” beginning on page 15 and “Cautionary Note Regarding Forward-Looking Statements.”

Corporate Sponsorship and Structure

We were recently incorporated pursuant to the laws of the State of Delaware as Oasis Petroleum Inc. to become a holding company for Oasis Petroleum LLC. Oasis Petroleum LLC was formed as a Delaware limited liability company on February 26, 2007 by certain members of our senior management team and private equity funds managed by EnCap Investments L.P., or EnCap. EnCap, which was formed in 1988, provides private equity to independent oil and gas companies. Since its inception, EnCap has formed fourteen oil and gas investment funds with aggregate capital commitments of approximately $7.0 billion.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, all of the interests in Oasis Petroleum LLC will be exchanged for common stock of Oasis Petroleum Inc., a recently formed Delaware corporation. As a result of the reorganization, Oasis Petroleum LLC will become a wholly owned subsidiary of Oasis Petroleum Inc. Upon completion of this offering, EnCap and its affiliates will initially own an approximate 31% indirect economic interest in us through OAS Holdco, the selling stockholder in this offering, which will initially own approximately 51% of our outstanding shares of common stock (or 45% if the underwriters’ over-allotment option is exercised in full) based on the initial public offering price of $14.00 per share. In addition, members of our management will initially own an approximate aggregate 14% interest in us through direct ownership of our common stock and through their indirect interest in OAS Holdco. For more information on our reorganization and the ownership of our common stock by our principal and selling stockholders, see “Corporate Reorganization” and “Principal and Selling Stockholders.”

The following diagrams indicate our current ownership structure and our ownership structure after giving effect to our corporate reorganization and this offering based on the initial public offering price of $14.00 per share and assuming no exercise of the underwriters’ over-allotment option. The ownership percentages for the current ownership structure diagram assume that all of the shares of the company that will be held by current investors are valued at the initial public offering price of $14.00 per share, less underwriting discounts and commissions, and the actual ownership percentages will vary based on actual distributions of cash or shares from OAS Holding Company LLC to its owners in the future. Please see “Corporate Reorganization.”


(1)		Certain of our officers and directors will be granted an aggregate of 176,250 shares of restricted common stock in connection with the closing of this offering. See “Executive Compensation and Other Information — Compensation Discussion and Analysis — Elements of Our Compensation and Why We Pay Each Element — Long-Term Equity Based Incentives.”
(2)		Gives effect to a required distribution of certain shares initially held by OAS Holdco to Oasis Petroleum Management LLC after this offering. Our executive officers and other key employees own the equity interests of Oasis Petroleum Management LLC. Please see “Principal and Selling Stockholders” and “Corporate Reorganization.”
(3)		Two members of our board of directors, Douglas E. Swanson, Jr. and Robert L. Zorich, are principals of EnCap.
(4)		Gives effect to required distributions of certain shares initially held by OAS Holdco to certain of its members, including OPM. Upon the completion of this offering, OAS Holding Company LLC will initially own at least a majority of our outstanding common stock. Please see “Corporate Reorganization.”

Corporate Information

Our principal executive offices are located at 1001 Fannin Street, Suite 202, Houston, Texas 77002, and our telephone number at that address is (713) 574-1770. We expect to have an operational website concurrently with the completion of this offering. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

THE OFFERING


Common stock offered by Oasis Petroleum Inc.		30,370,000 shares

Common stock offered by the selling stockholder		11,630,000 shares (17,930,000 shares if the underwriters’ over-allotment is exercised in full)

Total common stock offered		42,000,000 shares (48,300,000 shares if the underwriters’ over allotment is exercised in full)

Common stock to be outstanding after the offering		92,215,295 shares

Common stock owned by the selling stockholder after the offering		50,000,000 shares (43,700,000 shares if the underwriters’ over-allotment is exercised in full)

Over-allotment option		The selling stockholder has granted the underwriters a 30-day option to purchase up to an aggregate of 6,300,000 additional shares of our common stock to cover over-allotments.

Use of proceeds		We will receive approximately $395.7 million of net proceeds from the sale of the common stock by us in this offering after deducting underwriting discounts and estimated offering expenses. We intend to use a portion of net proceeds from this offering to repay all outstanding indebtedness under our revolving credit facility, approximately $75.0 million of which was outstanding on June 16, 2010. The remaining proceeds of approximately $320.7 million will be used to fund our exploration and development program. We will not receive any proceeds from the sale of shares by the selling stockholder; however, EnCap, certain of its affiliates, certain of our executive officers and affiliates of certain of the underwriters will indirectly receive proceeds from such sale as a result of a distribution of proceeds by the selling stockholder to its members. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds of this offering. See “Use of Proceeds,” “Corporate Reorganization” and “Underwriters.”

Dividend policy		We do not anticipate paying any cash dividends on our common stock. In addition, our revolving credit facility prohibits us from paying cash dividends. See “Dividend Policy.”

Risk factors		You should carefully read and consider the information beginning on page 15 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

New York Stock Exchange symbol		OAS

Summary Historical Consolidated and Unaudited Pro Forma Financial Data

You should read the following summary financial data in conjunction with “Selected Historical Consolidated and Unaudited Pro Forma Financial Data,” “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Set forth below is our summary historical consolidated financial data for the period from February 26, 2007, the date of inception of Oasis Petroleum LLC, through December 31, 2007, the years ended December 31, 2008 and 2009 and balance sheet data at December 31, 2008 and 2009, all of which have been derived from the audited financial statements of Oasis Petroleum LLC included elsewhere in this prospectus. Our historical financial data below as of March 31, 2009 and 2010 and for the three months ended March 31, 2009 and 2010 are derived from our unaudited consolidated financial statements and the notes thereto included elsewhere in this prospectus and, in our opinion, have been prepared on a basis consistent with the audited financial statements and the notes thereto and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. The balance sheet data at December 31, 2007 has been derived from the audited financial statements of Oasis Petroleum LLC not included elsewhere in this prospectus. The unaudited pro forma financial data for the year ended December 31, 2009, which reflects the effects of the acquisition of interests in certain oil and gas properties from Kerogen Resources, Inc., is derived from the unaudited pro forma financial information included elsewhere in this prospectus. The unaudited pro forma financial information has been prepared as if the acquisition had taken place on January 1, 2009.


	Historical
	Period from									Three Months						Pro Forma
	February 26, 2007			Year Ended						Ended						Year Ended
	(Inception) through			December 31,						March 31,						December 31,
	December 31, 2007			2008			2009			2009			2010			2009
	(In thousands)

Statement of operations data:
Oil and gas revenues	$	13,791		$	34,736		$	37,755		$	3,216		$	20,068		$	41,999
Expenses:
Lease operating expenses		2,946			7,073			8,691			1,807			2,977			10,274
Production taxes		1,211			3,001			3,810			268			1,910			4,160
Depreciation, depletion and amortization		4,185			8,686			16,670			2,528			5,849			19,233
Exploration expenses		1,164			3,222			1,019			(155	)		18			1,019
Rig termination(1)		—			—			3,000			3,000			—			3,000
Impairment of oil and gas properties(2)		1,177			47,117			6,233			441			3,077			6,233
Gain on sale of properties		—			—			(1,455	)		—			—			(1,455	)
Stock-based compensation expense(3)		—			—			—			—			5,200			—
General and administrative expenses		3,181			5,452			9,342			1,418			3,516			9,342

Total expenses	$	13,864		$	74,551		$	47,310		$	9,307		$	22,547		$	51,806

Operating loss		(73	)		(39,815	)		(9,555	)		(6,091	)		(2,479	)		(9,807	)
Other income (expense):
Change in unrealized gain (loss) on derivative instruments		(10,679	)		14,769			(7,043	)		(659	)		(391	)		(7,043	)
Realized gain (loss) on derivative instruments		(1,062	)		(6,932	)		2,296			1,442			(26	)		2,296
Interest expense		(1,776	)		(2,404	)		(912	)		(194	)		(338	)		(912	)
Other income (expense)		40			(9	)		5			(10	)		3			5

Total other income (expense)		(13,477	)		5,424			(5,654	)		579			(752	)		(5,654	)

Net loss	$	(13,550	)	$	(34,391	)	$	(15,209	)	$	(5,512	)	$	(3,231	)	$	(15,461	)


(1)		For a discussion of our rig termination expenses, see Note 10 to our audited consolidated financial statements.

(2)		In 2008, we recognized a $45.5 million non-cash impairment charge on our proved properties to reflect the impact of significantly lower oil prices and a $1.6 million impairment charge on our unproved properties due to expiring leases. See Note 2 to our audited consolidated financial statements.

(3)		In March 2010, we recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests to certain employees of the company. See Note 9 to our unaudited consolidated financial statements.


									As of
									March 31,
							As of		2010
	As of December 31,						March 31,		As Further
	2007		2008		2009		2010		Adjusted(1)
	(In thousands)

Balance sheet data:
Cash and cash equivalents	$	6,282	$	1,570	$	40,562	$	2,610	$	376,779
Net property, plant and equipment		92,918		114,220		181,573		209,744		209,744
Total assets		104,145		129,068		239,553		233,316		607,485
Long-term debt		46,500		26,000		35,000		23,000		—
Total members’/stockholders’ equity		36,350		82,459		171,850		173,819		589,856


	Period from
	February 26, 2007									Three Months Ended
	(Inception) through			Year Ended December 31,						March 31,
	December 31, 2007			2008			2009			2009			2010
	(In thousands)

Other financial data:
Net cash provided by (used in) operating activities	$	2,284		$	13,766		$	6,148		$	(9,482	)	$	7,702
Net cash used in investing activities		(91,988	)		(78,478	)		(80,756	)		(12,509	)		(32,241	)
Net cash provided by (used in) financing activities		95,986			60,000			113,600			24,000			(13,413	)
Adjusted EBITDA(2)		5,431			12,269			16,668			(1,845	)		11,642


(1)		Includes the effect of our corporate reorganization and the effect of this offering as described in “Corporate Reorganization,” “Capitalization” and “Dilution.”

(2)		Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net loss and net cash provided by operating activities, see “— Non-GAAP Financial Measure” below.

Set forth below is historical financial data for the six months ended June 30, 2007 for properties acquired from Bill Barrett Corporation, which constitute the accounting predecessor to Oasis Petroleum LLC. The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.


	Predecessor
	Six Months Ended
	June 30, 2007
	(In thousands)

Statement of operations data:
Oil and gas revenues	$	10,686
Direct operating expenses		3,490

Excess of revenues over direct operating expenses	$	7,196

Non-GAAP Financial Measure

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, exploration expenses, unrealized derivative gains and losses and non-cash stock-based compensation expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

Management believes Adjusted EBITDA is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net loss and net cash provided by operating activities, respectively.


	Period from
	February 26, 2007			Year Ended						Three Months Ended
	(Inception) through			December 31,						March 31,
	December 31, 2007			2008			2009			2009			2010
	(In thousands)

Adjusted EBITDA reconciliation to Net Loss:
Net loss	$	(13,550	)	$	(34,391	)	$	(15,209	)	$	(5,512	)	$	(3,231	)
Change in unrealized (gain) loss on derivative instruments		10,679			(14,769	)		7,043			659			391
Interest expense		1,776			2,404			912			194			338
Depreciation, depletion and amortization		4,185			8,686			16,670			2,528			5,849
Impairment of oil and gas properties		1,177			47,117			6,233			441			3,077
Exploration expenses		1,164			3,222			1,019			(155	)		18
Stock-based compensation expense		—			—			—			—			5,200

Adjusted EBITDA	$	5,431		$	12,269		$	16,668		$	(1,845	)	$	11,642

Summary Historical Operating and Reserve Data

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves as of the dates indicated. For additional information regarding our reserves, as well as the impact of the SEC’s new rules governing the presentation of reserve information, see “Business.” The reserve estimates at December 31, 2007 and 2008 presented in the table below are based on reports prepared by W.D. Von Gonten & Co., independent reserve engineers, and were prepared consistent with the former rules and regulations of the Securities and Exchange Commission, or the SEC, regarding oil and natural gas reserve reporting in effect during such periods. The reserve estimates at December 31, 2009 presented in the table below are based on a report prepared by DeGolyer and MacNaughton, independent reserve engineers, and were prepared consistent with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect.


	At December 31,
	2007			2008			2009

Reserve Data(1):
Estimated proved reserves:
Oil (MMBbls)		4.0			2.2			12.4
Natural gas (Bcf)		1.2			0.7			5.3
Total estimated proved reserves (MMBoe)		4.3			2.3			13.3
Estimated proved developed (MMBoe)		3.4			2.3			5.6
Percent developed		81	%		100	%		42	%
Estimated proved undeveloped (MMBoe)		0.8			—			7.7
PV-10 (in millions)(2)	$	121.8		$	17.7		$	133.5
Standardized Measure (in millions)(3)		121.8			17.7			133.5


(1)		Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

(2)		PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because as of December 31, 2009, we were a limited liability company not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, in connection with the closing of this offering, we will merge into a corporation that will become a holding company for Oasis Petroleum LLC. As a result, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. The PV-10 amounts included in the reports of W.D. Von Gonten & Co. at December 31, 2007 and at December 31, 2008 were $122.9 million and $19.2 million, respectively, because the PV-10 amounts included in such reports do not give effect to additional estimated plugging and abandonment costs.

(3)		Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. In connection with the closing of this offering, we will merge into a corporation that will be treated


		as a taxable entity for federal income tax purposes. Future calculations of Standardized Measure will include the effects of income taxes on future net revenues. For further discussion of income taxes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following table sets forth summary data with respect to our production results, average sales prices and production costs on a historical basis for the periods presented:


			Oasis Petroleum LLC
	Predecessor		Period from
	January 1, 2007		February 26, 2007		Year Ended				Three Months Ended
	through		(Inception) through		December 31,				March 31,
	June 30, 2007(1)		December 31, 2007(2)		2008		2009		2009		2010
Operating data:
Net production volumes:
Oil (MBbls)		190		159		379		658		102		270
Natural gas (MMcf)		69		73		123		326		27		160
Oil equivalents (MBoe)		202		171		400		712		106		297
Average daily production (Boe/d)				929		1,092		1,950		1,183		3,295
Average sales prices:
Oil, without realized derivatives (per Bbl)	$	53.73	$	83.96	$	88.07	$	55.32	$	30.68	$	70.21
Oil, with realized derivatives(3) (per Bbl)				77.27		69.79		58.82		44.83		70.12
Natural gas (per Mcf)		6.87		6.25		10.91		4.24		3.29		7.02
Costs and expenses (per Boe of production):
Lease operating expenses	$	12.79	$	17.23	$	17.70	$	12.21	$	16.98	$	10.04
Production taxes		4.49		7.08		7.51		5.35		2.52		6.44
Depreciation, depletion and amortization				24.47		21.73		23.42		23.75		19.73
General and administrative expenses				18.60		13.64		13.12		13.32		11.86
Stock-based compensation expense(4)				—		—		—		—		17.54


(1)		The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.

(2)		For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.

(3)		Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for hedge accounting. We have not made any estimates of the impact of commodities derivatives on the average sales price for our predecessor.

(4)		In March 2010, we recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests to certain employees of the company. See Note 9 to our unaudited consolidated financial statements.

RISK FACTORS

You should carefully consider the risks described below before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:


	•	worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

	•	the actions of the Organization of Petroleum Exporting Countries, or OPEC;

	•	the price and quantity of imports of foreign oil and natural gas;

	•	political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

	•	the level of global oil and natural gas exploration and production;

	•	the level of global oil and natural gas inventories;

	•	localized supply and demand fundamentals and transportation availability;

	•	weather conditions and natural disasters;

	•	domestic and foreign governmental regulations;

	•	speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

	•	price and availability of competitors’ supplies of oil and natural gas;

	•	technological advances affecting energy consumption; and

	•	the price and availability of alternative fuels.

Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. See also “— Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.” Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also “— The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.”

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:


	•	shortages of or delays in obtaining equipment and qualified personnel;

	•	facility or equipment malfunctions;

	•	unexpected operational events;

	•	pressure or irregularities in geological formations;

	•	adverse weather conditions, such as blizzards and ice storms;

	•	reductions in oil and natural gas prices;

	•	delays imposed by or resulting from compliance with regulatory requirements;

	•	proximity to and capacity of transportation facilities;

	•	title problems; and

	•	limitations in the market for oil and natural gas.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. See “Business — Our Operations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2009.

In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are

beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. For the years ended December 31, 2007 and 2008, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate in accordance with previous SEC requirements. In accordance with new SEC requirements for the year ended December 31, 2009, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:


	•	actual prices we receive for oil and natural gas;

	•	actual cost of development and production expenditures;

	•	the amount and timing of actual production; and

	•	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil prices decline by $1.00 per Bbl, then our PV-10 as of December 31, 2009 would decrease approximately $4.9 million. If natural gas prices decline by $0.10 per Mcf, then our PV-10 as of December 31, 2009 would decrease approximately $0.3 million.

Our business is difficult to evaluate because we have a limited operating history.

In considering whether to invest in our common stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. We were formed in February 2007 and, as a result, we have a limited operating history. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that our development plan is not completed or is delayed, our operating results will be adversely affected and our operations will differ materially from the activities described in this prospectus. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Operations in the Bakken and the Three Forks formations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flows used in investing activities were $47.4 million related to capital and exploration expenditures for the year ended December 31, 2009. Our capital expenditure budget for 2010 is approximately $220 million, with approximately $179 million allocated for drilling and completion operations. To date, our capital expenditures have been financed with capital contributions from EnCap and other private investors, borrowings under our revolving credit facility and net cash provided by operating activities. DeGolyer and MacNaughton projects that we will incur capital costs in excess of $113 million in the next three years to develop the proved undeveloped reserves in the Williston Basin covered by its December 31, 2009 reserve report. Because these costs cover less than 12% of our total potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop all of our potential drilling locations should we elect to do so. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

A significant improvement in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our revolving credit facility and net proceeds from this offering; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities or the sale of non-strategic assets. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of your common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base

redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities.

Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:


	•	our proved reserves;

	•	the level of oil and natural gas we are able to produce from existing wells;

	•	the prices at which our oil and natural gas are sold;

	•	the costs of developing and producing our oil and natural gas production;

	•	our ability to acquire, locate and produce new reserves;

	•	the ability and willingness of our banks to lend; and

	•	our ability to access the equity and debt capital markets.

If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken.

We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

We expect that we will not be the operator on approximately 48% of our identified gross drilling locations (approximately 18% of our identified net drilling locations). As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:


	•	the timing and amount of capital expenditures;

	•	the operator’s expertise and financial resources;

	•	approval of other participants in drilling wells;


	•	selection of technology; and

	•	the rate of production of reserves, if any.

This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

Substantially all of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.

As of December 31, 2009, approximately 99% of our proved reserves and approximately 96% of our production were located in the Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. See also “— Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” We generally do not purchase firm transportation on third party facilities and, therefore, the transportation of our production can be interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport our oil and natural gas.

The disruption of third-party facilities due to maintenance and/or weather could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.

Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.

The Williston Basin crude oil marketing and transportation environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for West Texas Intermediate (WTI) crude oil. For example, the difference between the WTI crude oil price and the Tesoro North Dakota Sweet oil price as of December 31, 2008 and 2009 was $14.80 per Bbl and $10.29 per Bbl, respectively. Such fluctuations and discounts could have a material adverse effect on our financial condition and results of operations.

The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 58% of our total proved reserves were classified as proved undeveloped as of December 31, 2009. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and

natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:


	•	environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

	•	abnormally pressured formations;

	•	mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

	•	personal injuries and death; and

	•	natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:


	•	injury or loss of life;

	•	damage to and destruction of property, natural resources and equipment;

	•	pollution and other environmental damage;

	•	regulatory investigations and penalties;

	•	suspension of our operations; and

	•	repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

We describe some of our drilling locations and our plans to explore those drilling locations in this prospectus. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

We have incurred losses from operations during certain periods since our inception and may continue to do so in the future.

We incurred net losses of $3.2 million and $5.5 million for the three months ended March 31, 2010 and 2009, respectively, $15.2 million and $34.4 million for the years ended December 31, 2009 and 2008, respectively, and $13.6 million in the period from February 26, 2007 (inception) through December 31, 2007. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus

may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Our potential drilling location inventories are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2009, only 86 of our 469 specifically identified potential future gross drilling locations were attributed to proved undeveloped reserves. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to a new SEC rule and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2009, we had leases representing 45,640 net acres expiring in 2010, 59,559 net acres expiring in 2011, and 31,642 net acres expiring in 2012. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of a permit before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and waste

water discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced a proposal to expand its final rule on greenhouse gas emissions reporting to include owners and operators of onshore oil and natural gas production. If the proposed rule is finalized in its current form, monitoring those newly covered sources would commence on January 1, 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases including carbon dioxide and methane that may contribute to warming of the Earth’s atmosphere and other climatic changes. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The U.S. Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale and tight sand formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of these bills, which are currently pending in the Energy and Commerce Committee and the Environmental and Public Works Committee of the House of Representatives and Senate, respectively, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Moreover, the EPA announced on March 18, 2010 that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Consequently, even if these bills are not adopted this year, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing activities.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect our operations.

To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Thomas B. Nusz, our Chairman, President and Chief Executive Officer, and Taylor L. Reid, our Executive Vice President and Chief Operating Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Williston Basin are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.

Our derivative activities could result in financial losses or could reduce our income.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:


	•	production is less than the volume covered by the derivative instruments;

	•	the counter-party to the derivative instrument defaults on its contract obligations; or

	•	there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.

In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

We enter into derivative contracts in order to hedge a portion of our oil production. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or the CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Separately, two committees of the House of Representatives, the Financial Services and Agriculture Committees, acted on October 15, 2009 and October 21, 2009, respectively, to adopt legislation that would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and major swap

participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” position in outstanding swaps other than swaps used for commercial hedging, or whose positions create substantial exposure to its counterparties or the system. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Our revolving credit facility contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our revolving credit facility includes certain covenants that, among other things, restrict:


	•	our investments, loans and advances and the payment of dividends and other restricted payments;

	•	our incurrence of additional indebtedness;

	•	the granting of liens, other than liens created pursuant to the revolving credit facility and certain permitted liens;

	•	mergers, consolidations and sales of all or a substantial part of our business or properties;

	•	the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;

	•	the sale of assets (other than production sold in the ordinary course of business); and

	•	our capital expenditures.

Our revolving credit facility requires us to maintain certain financial ratios, such as leverage ratios. All of these restrictive covenants may restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Our level of indebtedness may increase and reduce our financial flexibility.

Upon the completion of this offering, we expect to have no indebtedness outstanding and will have a borrowing capacity of $70 million under our revolving credit facility. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:


	•	a significant portion of our cash flows could be used to service our indebtedness;

	•	a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

	•	the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

	•	a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

	•	our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

	•	a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

	•	a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.

Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($9.1 million in receivables at December 31, 2009), which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties ($4.6 million at December 31, 2009), joint interest receivables ($1.3 million at December 31, 2009), and commodity derivatives contracts ($0.2 million at December 31, 2009).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year ended December 31, 2008, sales to Tesoro Refining and Marketing Company and Texon L.P. accounted for approximately 57% and 14%, respectively, of our total sales. For the year ended December 31, 2009, sales to Tesoro Refining and

Marketing Company and Texon L.P. accounted for approximately 32% and 30%, respectively, of our total sales. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:


	•	recoverable reserves;

	•	future oil and natural gas prices and their appropriate differentials;

	•	development and operating costs; and

	•	potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:


	•	diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

	•	challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

	•	difficulty associated with coordinating geographically separate organizations; and

	•	challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by

risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Risks Relating to the Offering and our Common Stock

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid trading market for our common stock may not develop and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholder and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriters” section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in the offering.

The following factors could affect our stock price:


	•	our operating and financial performance and drilling locations, including reserve estimates;

	•	quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

	•	changes in revenue or earnings estimates or publication of reports by equity research analysts;

	•	speculation in the press or investment community;

	•	sales of our common stock by us, the selling stockholder or other stockholders, or the perception that such sales may occur;

	•	general market conditions, including fluctuations in commodity prices; and

	•	domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

Purchasers of common stock in this offering will experience immediate and substantial dilution of $7.60 per share.

Purchasers of our common stock in this offering will experience an immediate and substantial dilution of $7.60 per share in the pro forma as adjusted net tangible book value per share of common stock from the initial public offering price, and our pro forma as adjusted net tangible book value as of March 31, 2010 after giving effect to this offering would be $6.40 per share. See “Dilution” for a complete description of the calculation of net tangible book value.

Because we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:


	•	institute a more comprehensive compliance function;

	•	design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

	•	comply with rules promulgated by the NYSE;

	•	prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

	•	establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

	•	involve and retain to a greater degree outside counsel and accountants in the above activities; and

	•	establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our Audit Committee, and qualified executive officers.

In connection with past audits and reviews of our financial statements, our independent registered public accounting firm identified and reported adjustments to management. Certain of such adjustments were deemed to be the result of internal control deficiencies that constitute material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations -Internal Controls and Procedures.”

In response, we have begun the process of evaluating our internal control over financial reporting, although we are in the early phases of our review and will not complete our review until well after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Although remediation efforts are still in progress, management has taken steps to address the causes of our audit and interim period adjustments and to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from making any cash dividends pursuant to the terms of our revolving credit facility. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock that will prevail in the market after this offering will ever exceed the price that you pay.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will

have 92,215,295 outstanding shares of common stock. This number includes 42,000,000 shares that we and the selling stockholder are selling in this offering (assuming no exercise of the underwriters’ over-allotment option), which may be resold immediately in the public market. Following the completion of this offering and after certain distributions by the selling stockholder, the selling stockholder will own 47,154,296 shares, or approximately 51% of our total outstanding shares, and certain of our affiliates will own 2,750,206 shares, approximately 3% of our outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriters,” but may be sold into the market in the future. We expect that the selling stockholder will be a party to a registration rights agreement with us which will require us to effect the registration of its shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. The holders of the remaining 310,793 shares and a small portion of shares owned by our affiliates which will be distributed to non-officer employees and other non-affiliates totaling up to approximately 575,000 shares, or approximately 0.6% of our outstanding shares, are not subject to lock-up agreements and, subject to compliance with Rule 144 under the Securities Act, may sell such shares into the public market.

As soon as practicable after this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 7,200,000 shares of our common stock issued or reserved for issuance under our stock incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under this registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:


	•	a classified board of directors, so that only approximately one-third of our directors are elected each year;

	•	limitations on the removal of directors; and

	•	limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

The concentration of our capital stock ownership among our largest stockholders and their affiliates will limit your ability to influence corporate matters.

Upon completion of this offering (assuming no exercise of the underwriters’ over-allotment option), OAS Holdco, the selling stockholder, will initially own up to approximately 54% of our outstanding common stock and EnCap and its affiliates will own approximately 61% of the selling stockholder (based on the initial public offering price of $14.00 per share). While a portion of these shares will be distributed by OAS Holdco after the consummation of this offering as described under “Corporate Reorganization — LLC Agreement of OAS

Holdco,” we expect EnCap and its affiliates will continue to control OAS Holdco, and OAS Holdco will continue to own in excess of 94% of these shares after this distribution. Consequently, EnCap and its affiliates will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and EnCap and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. EnCap is a private equity firm in the business of making investments in entities primarily in the U.S. oil and gas industry. As a result, EnCap’s existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

We have also renounced our interest in certain business opportunities. See “— Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.”

Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time presented to EnCap or its affiliates or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or her capacity as our director or officer. We will also enter into a business opportunity agreement with EnCap that contains similar contractual provisions.

As a result, EnCap or its affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to EnCap and its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See “Description of Capital Stock.”

We expect to be a “controlled company” within the meaning of the NYSE rules and, if applicable, would qualify for and will rely on exemptions from certain corporate governance requirements.

Because OAS Holdco will own a majority of our outstanding common stock following the completion of this offering, we expect to be a “controlled company” as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including:


	•	the requirement that a majority of our board of directors consist of independent directors;

	•	the requirement that our Nominating and Governance Committee be composed entirely of independent directors with a written charter addressing the Committee’s purpose and responsibilities; and


	•	the requirement that our Compensation Committee be composed entirely of independent directors with a written charter addressing the Committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a “controlled company.” Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. EnCap’s significant ownership interest could adversely affect investors’ perceptions of our corporate governance.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

On February 1, 2010, the White House released President Obama’s budget proposal for the fiscal year 2011, or the Budget Proposal. Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences currently available to coal, oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities, and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the United States.

It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the Budget Proposal or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production and could negatively impact the value of an investment in our shares.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:


	•	business strategy;

	•	reserves;

	•	technology;

	•	cash flows and liquidity;

	•	financial strategy, budget, projections and operating results;

	•	oil and natural gas realized prices;

	•	timing and amount of future production of oil and natural gas;

	•	availability of drilling and production equipment;

	•	availability of oil field labor;

	•	the amount, nature and timing of capital expenditures, including future development costs;

	•	availability and terms of capital;

	•	drilling of wells;

	•	competition and government regulations;

	•	marketing of oil and natural gas;

	•	exploitation or property acquisitions;

	•	costs of exploiting and developing our properties and conducting other operations;

	•	general economic conditions;

	•	competition in the oil and natural gas industry;

	•	effectiveness of our risk management activities;

	•	environmental liabilities;

	•	counterparty credit risk;

	•	governmental regulation and taxation of the oil and natural gas industry;

	•	developments in oil-producing and natural gas-producing countries;

	•	uncertainty regarding our future operating results;

	•	estimated future net reserves and present value thereof; and

	•	plans, objectives, expectations and intentions contained in this prospectus that are not historical.

All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

USE OF PROCEEDS

We will receive net proceeds of approximately $395.7 million from the sale of the common stock by us in this offering after deducting estimated expenses and underwriting discounts and commissions of approximately $29.5 million. We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholder.

We intend to use the net proceeds from this offering to (i) repay all outstanding indebtedness under our revolving credit facility, approximately $75.0 million of which was outstanding on June 16, 2010, and (ii) fund our exploration and development program. We have the ability to reborrow amounts repaid under our revolving credit facility for working capital or other purposes. We intend to use the following amounts for the above uses:


	Amount
Use of Proceeds	(In millions)

Repayment of revolving credit facility	$	75.0
Exploration and drilling program		320.7

Total	$	395.7

Our revolving credit facility matures in February 2014 and bears interest at a variable rate, which was approximately 3.0% per annum as of June 16, 2010. Our outstanding borrowings under our revolving credit facility were incurred to fund exploration, development and other capital expenditures. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering.

We estimate that the selling stockholder will receive net proceeds of approximately $153.1 million from the sale of 11,630,000 common shares in this offering after deducting underwriting discounts. If the underwriters’ over-allotment option is exercised in full, we estimate that the selling stockholder’s net proceeds will be approximately $236.0 million. We will pay all expenses related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling stockholder.

EnCap and certain of its affiliates, certain of our executive officers and affiliates of certain of the underwriters will indirectly receive proceeds from the sale of shares by the selling stockholder as a result of a distribution of proceeds by the selling stockholder to its members.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our revolving credit facility prohibits us from paying cash dividends.

CAPITALIZATION

The following table sets forth the capitalization of Oasis Petroleum LLC and Oasis Petroleum Inc., as applicable, as of March 31, 2010,


	•	on an actual basis;

	•	on an as adjusted basis to give effect to (i) the transactions described under “Corporate Reorganization” and (ii) the issuance of an aggregate of 215,295 shares of restricted common stock as described under “Executive Compensation and Other Information — Compensation Discussion and Analysis — Elements of Our Compensation and Why We Pay Each Element — Long-Term Equity Based Incentives.” that will occur simultaneously with the closing of this offering; and

	•	on an as further adjusted basis to give effect to this offering and the application of the net proceeds as set forth under “Use of Proceeds.”

You should read the following table in conjunction with “Use of Proceeds,” “Selected Historical Consolidated and Unaudited Pro Forma Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto appearing elsewhere in this prospectus.


	As of March 31, 2010
							As Further
	Actual			As Adjusted			Adjusted
	(In thousands)

Cash and cash equivalents(1)	$	2,610		$	2,610		$	376,779


Long-term debt, including current maturities:
Revolving credit facility(2)	$	23,000		$	23,000		$	—

Total long-term debt		23,000			23,000			—

Members’ / stockholders’ equity:
Capital contributions		235,000			—			—
Common stock, $0.01 par value; 1,000 shares authorized, issued and outstanding (actual); 300,000,000 shares authorized (as adjusted and as further adjusted); 61,845,295 shares issued and outstanding (as adjusted); 92,215,295 shares issued and outstanding (as further adjusted)		—			616			920
Preferred stock, $0.01 par value; no shares authorized (actual); 50,000,000 shares authorized (as adjusted and as further adjusted); no shares issued and outstanding (actual; as adjusted and as further adjusted)		—			—			—
Additional paid-in capital		5,200			239,584			664,460
Retained earnings (accumulated loss)(3)		(66,381	)		(75,524	)		(75,524	)

Total members’/stockholders’ equity		173,819			164,676			589,856

Total capitalization	$	196,819		$	187,676		$	589,856


(1)		As of June 16, 2010, our cash and cash equivalents were $4.5 million.

(2)		On February 26, 2010, we entered into an amended and restated revolving credit facility, which will have a borrowing base of $70 million upon the completion of this offering. Prior to amending and restating our revolving credit facility, we repaid substantially all outstanding indebtedness under our revolving credit facility with cash on hand. As of June 16, 2010, we had $75.0 million of indebtedness outstanding under our revolving credit facility. We intend to repay in full all amounts outstanding under our revolving credit facility with a portion of the net proceeds from this offering.

(3)		In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $9.1 million will be established for differences between the book and tax basis of our assets and liabilities and a corresponding expense will be recorded to net income from continuing operations.

DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of March 31, 2010, after giving pro forma effect to the transactions described under “Corporate Reorganization,” was approximately $164.7 million, or $2.66 per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering including giving effect to (i) our corporate reorganization and (ii) the issuance of restricted stock awards at the closing of this offering. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of March 31, 2010 would have been approximately $589.9 million, or $6.40 per share. This represents an immediate increase in the net tangible book value of $3.74 per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $7.60 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:


Initial public offering price per share			$	14.00
Pro forma net tangible book value per share as of March 31, 2010 (after giving effect to our corporate reorganization)	$	2.66
Increase per share attributable to new investors in this offering		3.74

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering				6.40

Dilution in pro forma net tangible book value per share to new investors in this offering			$	7.60

The following table summarizes, on an adjusted pro forma basis as of March 31, 2010, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering calculated before deduction of estimated underwriting discounts and commissions:


	Shares Acquired					Total Consideration					Average Price
	Number		Percent			Amount		Percent			per Share

Existing stockholders(1)(2)		61,845,295		67	%	$	238,014,130		36	%	$	3.85
New investors(3)		30,370,000		33	%		425,180,000		64	%		14.00

Total		92,215,295		100	%	$	663,194,130		100	%	$	7.19


(1)		The number of shares disclosed for the existing stockholders includes 11,630,000 shares being sold by the selling stockholder in this offering. The total consideration and average price per share represents the consideration paid in connection with our corporate reorganization. See “Corporate Reorganization.”

(2)		The number of shares presented above for the existing stockholders includes 215,295 shares of restricted stock to be issued upon the consummation of this offering. See “Executive Compensation and Other Information — Compensation Discussion and Analysis — Elements of Our Compensation and Why We Pay Each Element — Long-Term Equity Based Incentives.”

(3)		The number of shares disclosed for the new investors does not include the 11,630,000 shares being purchased by the new investors from the selling stockholder in this offering.

SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

You should read the following selected financial data in conjunction with “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and unaudited pro forma financial information and related notes thereto included elsewhere in this prospectus. We believe that the assumptions underlying the preparation of our historical consolidated financial statements and unaudited pro forma financial data are reasonable. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.


	Historical
	Period from									Three Months						Pro Forma
	February 26, 2007			Year Ended						Ended						Year Ended
	(Inception) through			December 31,						March 31,						December 31,
	December 31, 2007			2008			2009			2009			2010			2009
	(In thousands)

Statement of operations data:
Oil and gas revenues	$	13,791		$	34,736		$	37,755		$	3,216		$	20,068		$	41,999
Expenses:
Lease operating expenses		2,946			7,073			8,691			1,807			2,977			10,274
Production taxes		1,211			3,001			3,810			268			1,910			4,160
Depreciation, depletion and amortization		4,185			8,686			16,670			2,528			5,849			19,233
Exploration expenses		1,164			3,222			1,019			(155	)		18			1,019
Rig termination(1)		—			—			3,000			3,000			—			3,000
Impairment of oil and gas properties(2)		1,177			47,117			6,233			441			3,077			6,233
Gain on sale of properties		—			—			(1,455	)		—			—			(1,455	)
Stock-based compensation expense(3)		—			—			—			—			5,200			—
General and administrative expenses		3,181			5,452			9,342			1,418			3,516			9,342

Total expenses		13,864			74,551			47,310			9,307			22,547			51,806

Operating loss		(73	)		(39,815	)		(9,555	)		(6,091	)		(2,479	)		(9,807	)
Other income (expense):
Change in unrealized gain (loss) on derivative instruments		(10,679	)		14,769			(7,043	)		(659	)		(391	)		(7,043	)
Realized gain (loss) on derivative instruments		(1,062	)		(6,932	)		2,296			1,442			(26	)		2,296
Interest expense		(1,776	)		(2,404	)		(912	)		(194	)		(338	)		(912	)
Other income (expense)		40			(9	)		5			(10	)		3			5

Total other income (expense)		(13,477	)		5,424			(5,654	)		579			(752	)		(5,654	)

Net loss	$	(13,550	)	$	(34,391	)	$	(15,209	)	$	(5,512	)	$	(3,231	)	$	(15,461	)


(1)		For a discussion of our rig termination expenses, see Note 10 to our audited consolidated financial statements.

(2)		In 2008, we recognized a $45.5 million non-cash impairment charge on our proved properties to reflect the impact of significantly lower oil prices and a $1.6 million impairment charge on our unproved properties due to expiring leases. See Note 2 to our audited consolidated financial statements.

(3)		In March 2010, we recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests to certain employees of the company. See Note 9 to our unaudited consolidated financial statements.


									As of
									March 31,
							As of		2010
	As of December 31,						March 31,		As Further
	2007		2008		2009		2010		Adjusted(1)
	(In thousands)

Balance sheet data:
Cash and cash equivalents	$	6,282	$	1,570	$	40,562	$	2,610	$	376,779
Net property, plant and equipment		92,918		114,220		181,573		209,744		209,744
Total assets		104,145		129,068		239,553		233,316		607,485
Long-term debt		46,500		26,000		35,000		23,000		—
Total members’/stockholders’ equity		36,350		82,459		171,850		173,819		589,856


	Period from
	February 26, 2007									Three Months Ended
	(Inception) through			Year Ended December 31,						March 31,
	December 31, 2007			2008			2009			2009			2010
	(In thousands)

Other financial data:
Net cash provided by (used in) operating activities	$	2,284		$	13,766		$	6,148		$	(9,482	)	$	7,702
Net cash used in investing activities		(91,988	)		(78,478	)		(80,756	)		(12,509	)		(32,241	)
Net cash provided by (used in) financing activities		95,986			60,000			113,600			24,000			(13,413	)
Adjusted EBITDA(2)		5,431			12,269			16,668			(1,845	)		11,642


(1)		Includes the effect of our corporate reorganization and the effect of this offering as described in “Corporate Reorganization,” “Capitalization” and “Dilution.”

(2)		Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net loss and net cash provided by operating activities, see “Summary Historical Consolidated and Unaudited Pro Forma Financial Data — Non-GAAP Financial Measure.”

Set forth below is historical financial data for the years ended December 31, 2005 and 2006 and the six months ended June 30, 2007 for properties acquired from Bill Barrett Corporation, which constitute the accounting predecessor to Oasis Petroleum LLC. The historical financial data for the years ended December 31, 2005 and 2006 was derived from the historical accounting records of Bill Barrett Corporation. The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.


	Predecessor
	Year Ended December 31,				Six Months Ended
	2005		2006		June 30, 2007
	(In thousands)

Statement of operations data:
Oil and gas revenues	$	20,494	$	25,207	$	10,686
Direct operating expenses		4,283		5,872		3,490

Excess of revenues over direct operating expenses	$	16,211	$	19,335	$	7,196

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in the prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. Since our inception, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken formation.

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, our willingness to acquire non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.

Our company was formed in February 2007. We began active oil and natural gas operations in July 2007 following the acquisition of properties in the Williston Basin consisting of approximately 175,000 net leasehold acres and approximately 1,000 Boe/d of then-current net production, substantially forming our core leasehold position in the West Williston project area. In May 2008, we entered into a farm-in and purchase arrangement under which we earned or acquired approximately 48,000 net leasehold acres, establishing our initial position in the East Nesson project area. In June 2009, we acquired approximately 37,000 net leasehold acres with then-current net production of approximately 800 Boe/d, approximately 92% of which was from the Williston Basin. This acquisition consolidated our acreage in the East Nesson project area and established our Sanish project area. In September 2009, we acquired an additional 46,000 net leasehold acres with then-current production of approximately 300 Boe/d. This acquisition further consolidated our acreage in the East Nesson project area. Our acquisitions were financed with a combination of borrowings under our revolving credit

facility, cash flows provided by operating activities and capital contributions made by EnCap and other private investors.


		Adjusted		Production at
	Closing Date of	Purchase Price(1)		Acquisition		Net Acreage at
Project Areas of Acquired Properties	Acquisition	(In millions)		(Boe/d)		Acquisition

West Williston(2)	June 22, 2007	$	83		1,000		175,000
East Nesson(3)	May 16, 2008		16		—		48,000
East Nesson/Sanish	June 15, 2009		27		800		37,000
East Nesson	September 30, 2009		11		300		46,000


(1)		Represents initial purchase price plus closing adjustments.

(2)		For accounting purposes, results from our West Williston acquisition are included in our results of operations effective July 1, 2007.

(3)		Our farm-in and purchase arrangement required an initial payment of $15.6 million and obligated us to spend $15.1 million of drilling costs on behalf of the other parties.

Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Our initial acquisition of properties in the Williston Basin was completed in June 2007 from Bill Barrett Corporation, which constitutes our accounting predecessor. Our historical results include the results from our recent acquisitions beginning on the closing dates indicated in the table above. See our unaudited pro forma financial information and related notes included elsewhere in this prospectus for more information about how our historical results of operations would have been affected had our June 2009 acquisition been completed on January 1, 2009.

Our 2009 activities included development and exploration drilling in each of our primary project areas. Our current activities are focused on evaluating and developing our asset base, optimizing our acreage positions and evaluating potential acquisitions. At December 31, 2009, based on the reserve report prepared by our independent reserve engineers, we had 13.3 MMBoe of estimated net proved reserves with a PV-10 of $133.5 million and a Standardized Measure of $133.5 million. At December 31, 2008, we had 2.3 MMBoe of estimated net proved reserves with a PV-10 of $17.7 million and a Standardized Measure of $17.7 million. Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009, and the index prices were $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and gas activities, commodity prices have experienced significant fluctuations. Our quarterly average net realized oil prices are shown in the table below.


									Year										Year
									Ended										Ended
	2008								December 31,		2009								December 31,		2010
	Q1		Q2		Q3		Q4		2008		Q1		Q2		Q3		Q4		2009		Q1

Average Realized Oil Prices($/Bbl)(1)	$	88.65	$	114.30	$	108.73	$	44.99	$	88.07	$	30.68	$	52.47	$	57.00	$	65.09	$	55.32	$	70.21
Average Price Differential(2)		9%		8%		8%		23%		11%		29%		13%		17%		14%		17%		11%


(1)		Realized oil prices do not include the effect of realized derivative contract settlements.

(2)		Price differential compares realized oil prices to West Texas Intermediate crude index prices.

The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Williston Basin. In general, higher commodity prices and higher production rates from the application of new technology caused drilling activity in the Williston Basin to increase over the course of 2007 and 2008 before peaking in the fourth quarter of 2008 with over 90 active drilling rigs in the Williston Basin. This level of drilling activity resulted in record levels of oil production by early 2009 and the aggregate Williston Basin oil production temporarily exceeded the takeaway capacity that transports the oil to refining markets both inside and outside of the basin. As a result, the price differential, or Williston Basin discount, between our realized prices as compared to the West Texas Intermediate crude oil index price averaged approximately 23% and 29% in the fourth quarter of 2008 and the first quarter of 2009, respectively. By comparison, our Williston Basin discount averaged approximately 11% and 17% for the year ended December 31, 2008 and the year ended December 31, 2009, respectively.

The global and national financial crisis of late 2008 and 2009 reduced overall commodity demand. The combination of reduced oil demand and oil oversupply in the Williston Basin caused a significant decline in our realized crude oil prices during the fourth quarter of 2008 and the first quarter of 2009. Due to the decline in commodity prices and the large increases in realized price differentials, drilling rig activity declined to approximately 30 active rigs in the Williston Basin by the second quarter of 2009.

Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. From December 31, 2007 to December 31, 2008, our standardized measure of discounted future net cash flows attributable to proved oil and natural gas reserves declined from $121.8 million to $17.7 million primarily due to net decreases of both value and reserve quantities from the decline in oil and gas commodity prices described above.

During the fourth quarter of 2008, we also recorded a $45.5 million charge to recognize an impairment to the carrying value of our proved oil and gas properties as a result of the decline in oil and gas commodity prices. In response to the commodity pricing environment in the fourth quarter of 2008, we reduced our planned 2009 capital expenditure program and also initiated discussions for early termination of two of our drilling rig contracts. In addition, although we drilled ten wells in the second half of 2008, we elected to delay the completion of five of the wells until mid 2009, as a result of lower commodity prices without a corresponding decrease in completion costs available from our vendors. We subsequently completed these wells in mid 2009 when completion costs were significantly lower.

While we experienced reduced cash flows from operations during this period due to lower oil and gas commodity prices, we had access to $69.6 million of remaining private equity funding capacity and $3.5 million of unused borrowing base capacity at December 31, 2008 under our previous revolving credit facility. Our financial position allowed us to pursue the preservation of our leasehold acreage positions by extending leases and purchasing leases instead of drilling. In addition, we maintained the financial capacity to endure the downturn in the commodity and financial markets as well as to position ourselves for acquisitions in 2009.

Oil and gas prices for 2009 increased significantly from the fourth quarter of 2008. The higher commodity prices, as well as continued successes in the application of completion technologies in the Bakken formation, caused the active drilling rig count in the Williston Basin to exceed 100 rigs at March 31, 2010. Although additional Williston Basin transportation takeaway capacity was added in 2009, we believe that the

expected production increases from the elevated 2010 drilling activity may cause price differentials to exceed the historical average range of approximately 10% to 15% of the West Texas Intermediate crude oil index price.

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

The following table summarizes our revenues and production data for the periods indicated.


	Predecessor		Oasis Petroleum LLC
			Period from
	January 1, 2007		February 26, 2007		Year Ended
	through		(Inception) through		December 31,				Three Months Ended March 31,
	June 30, 2007(1)		December 31, 2007(2)		2008		2009		2009		2010
Operating results (in thousands):
Revenues
Oil	$	10,211	$	13,335	$	33,396	$	36,376	$	3,127	$	18,943
Natural gas		475		456		1,340		1,379		89		1,125

Total oil and gas revenues	$	10,686	$	13,791	$	34,736	$	37,755	$	3,216	$	20,068
Production data:
Oil (MBbls)		190		159		379		658		102		270
Natural gas (MMcf)		69		73		123		326		27		160
Oil equivalents (MBoe)		202		171		400		712		106		297
Average daily production (Boe/d)				929		1,092		1,950		1,183		3,295
Average sales prices:
Oil, without realized derivatives (per Bbl)	$	53.73	$	83.96	$	88.07	$	55.32	$	30.68	$	70.21
Oil, with realized derivatives (3) (per Bbl)				77.27		69.79		58.82		44.83		70.12
Natural gas (per Mcf)		6.87		6.25		10.91		4.24		3.29		7.02


(1)		The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus.

(2)		For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.

(3)		Realized prices include realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting. We have not made any estimates of the impact of commodities derivatives on the average sales price for our predecessor.

Three months ended March 31, 2010 as compared to three months ended March 31, 2009

Oil and Natural Gas Revenues. Our oil and natural gas sales revenues increased $16.9 million, or over 500%, to $20.1 million during the first quarter ended March 31, 2010 as compared to the first quarter ended March 31, 2009. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 2,112 Boe per day or 179% to

3,295 Boe per day during the first quarter ended March 31, 2010 as compared to the first quarter ended March 31, 2009. The increase in average daily production sold was primarily due to the Sanish and East Nesson acquisitions completed in the second and third quarters of 2009, respectively, and as a result of the company’s well completions during 2009 and the first quarter of 2010. The Sanish and East Nesson acquisitions contributed approximately 750 Boe per day during the first quarter of 2010, and well completions in our Sanish, East Nesson and West Williston project areas contributed approximately 750 Boe per day, 560 Boe per day, and 220 Boe per day, respectively, during 2009 and the first quarter of 2010. The higher production amounts sold contributed to $12.7 million of the revenue increase and the remaining $4.2 million increase was attributable to higher oil sales prices during the first quarter ended March 31, 2010. Average oil sales prices, without realized derivatives, increased by $39.53 per barrel or 129% to an average of $70.21 per barrel for the first quarter ended March 31, 2010 as compared to the first quarter ended March 31, 2009.

Year ended December 31, 2009 as compared to year ended December 31, 2008

Oil and Natural Gas Revenues. Our oil and natural gas sales revenues increased $3.0 million, or 9%, to $37.8 million during the year ended December 31, 2009 as compared to the year ended December 31, 2008. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 858 Boe per day or 79% to 1,950 Boe per day during the year ended December 31, 2009 as compared to the year ended December 31, 2008. The increase in average daily production sold was primarily due to the Sanish and East Nesson acquisitions completed in 2009, which contributed approximately 390 Boe per day, and well completions in our Sanish and East Nesson project areas, which contributed 168 Boe per day and 213 Boe per day, respectively. This $16.2 million revenue increase attributable to higher production sold was almost entirely offset by a $13.2 million revenue reduction attributable to lower oil sales prices during the year ended December 31, 2009. Average oil sales prices, without realized derivatives, declined by $32.75 per barrel or 37% to an average of $55.32 per barrel for the year ended December 31, 2009 as compared to the year ended December 31, 2008.

Year ended December 31, 2008 as compared to period from February 26, 2007 (Inception) through December 31, 2007

Oil and Natural Gas Revenues. Our oil and natural gas sales revenues increased $20.9 million, or 152%, to $34.7 million for the year ended December 31, 2008 compared to the period from February 26, 2007 (inception) through December 31, 2007. This increase was primarily a result of production from properties acquired in our West Williston project area, which we owned for all of 2008 as compared to only the last six months in 2007. Average oil sales prices, without realized derivatives, increased by $4.11 per barrel or 5% to an average of $88.07 per barrel for the year ended December 31, 2008 as compared to the period ended December 31, 2007.

When comparing our revenue for the period from February 26, 2007 (inception) through December 31, 2007 to our predecessor’s revenues for the period from January 1 through June 30, 2007, our revenues increased by $3.1 million or 29% to $13.8 million. The revenue increase is primarily due to average oil sales prices, without realized derivatives, that increased by $30.23 per barrel or 56% to an average of $83.96 per barrel.

Expenses


	•	Lease operating expenses. Lease operating expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, utilities, maintenance, repairs and workover expenses related to our oil and natural gas properties.

	•	Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in our


		various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.


	•	Depreciation, depletion and amortization. Depreciation, depletion and amortization includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs to each unit of production using the units-of-production method.

	•	Exploration expenses. Exploration expenses consist of exploratory dry hole expenses and costs incurred in evaluating areas that are considered to have prospective oil and natural gas reserves, including costs for topographical, geological and geophysical studies, rights of access to properties and costs of carrying and retaining undeveloped properties, such as delay rentals.

	•	Impairment of unproved and proved properties. These costs include unproved property impairment and costs associated with lease expirations. We could also record impairment charges for proved properties if the carrying value exceeds estimated future cash flows. See “— Impairment of proved properties.”

	•	Stock-based compensation expense. This expense consists of a one-time non-cash charge for stock-based compensation associated with Oasis Petroleum Management LLC granting Class C Common Unit interests (“C Units”) to certain of our employees in March 2010. The C Units were granted to individuals who were employed by the company as of February 1, 2010 and who were not executive officers or key employees with an existing capital investment in Oasis Petroleum Management LLC. The C Units immediately vested upon granting to the employees and provide an opportunity for employees to participate in appreciation realized through a future sale of the company, an initial public offering of the company and/or future sales or distributions of the company’s shares indirectly held by Oasis Petroleum Management LLC. We used a fair-value-based method to determine the value of stock-based compensation awarded to our employees.

	•	General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance.

Other Income (Expense)


	•	Change in unrealized gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil and natural gas. This account activity represents the recognition of gains and losses associated with our open derivative contracts as commodity prices and commodity derivative contracts change.

	•	Realized gain (loss) on derivative instruments, net. We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of crude oil and natural gas. The account activity represents our realized gains and losses on the settlement of these commodity derivative instruments.

	•	Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facility in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees as interest expense.

	•	Income tax expense. As of December 31, 2009, we were a limited liability company not subject to entity level income tax. Accordingly, no provision for federal or state corporate income taxes has been provided for the year ended December 31, 2009 or prior years because taxable income is allocated directly to our equity holders. In connection with the closing of this offering, we will merge into a


		corporation that will be subject to federal and state entity-level taxation. In connection with our corporate reorganization, a net deferred tax liability will be established for differences between the tax and book basis of our assets and liabilities and a corresponding “first day” tax expense will be recorded to net income from continuing operations. We estimate the net deferred tax liability to be approximately $9.1 million. We do not expect to report any income tax benefit or expense for 2010. Based on our history of losses since inception and deductions primarily related to intangible drilling costs, or IDCs, that are expected to exceed 2010 earnings, we expect to generate net tax benefits in our income statement and record tax assets on our balance sheet. However, due to uncertainty about our ability to ultimately realize our tax benefits, we will record a full valuation allowance against the tax assets which offsets the net tax benefits. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.

The following table summarizes our operating expenses for the periods indicated.


	Predecessor		Oasis Petroleum LLC
			Period from									Three Months
	January 1, 2007		February 26, 2007			Year Ended						Ended
	through		(Inception) through			December 31,						March 31,
	June 30, 2007(1)		December 31, 2007(2)			2008			2009			2009			2010
	(In thousands, except production cost and expense (per Boe of production))
Expenses:
Lease operating expenses	$	2,583	$	2,946		$	7,073		$	8,691		$	1,807		$	2,977
Production taxes		907		1,211			3,001			3,810			268			1,910
Depreciation, depletion and amortization				4,185			8,686			16,670			2,528			5,849
Exploration expenses				1,164			3,222			1,019			(155	)		18
Rig termination				—			—			3,000			3,000			—
Impairment of oil and gas properties				1,177			47,117			6,233			441			3,077
Gain on sale of properties				—			—			(1,455	)		—			—
Stock-based compensation expense				—			—			—			—			5,200
General and administrative expenses				3,181			5,452			9,342			1,418			3,516

Total expenses			$	13,864		$	74,551		$	47,310		$	9,307		$	22,547

Operating loss				(73	)		(39,815	)		(9,555	)		(6,091	)		(2,479	)
Other income (expense):
Change in unrealized gain (loss) on derivative instruments				(10,679	)		14,769			(7,043	)		(659	)		(391	)
Realized gain (loss) on derivative instruments, net				(1,062	)		(6,932	)		2,296			1,442			(26	)
Interest expense				(1,776	)		(2,404	)		(912	)		(194	)		(338	)
Other income (expense)				40			(9	)		5			(10	)		3

Total other income (expense)				(13,477	)		5,424			(5,654	)		579			(752	)

Net loss			$	(13,550	)	$	(34,391	)	$	(15,209	)	$	(5,512	)	$	(3,231	)

Cost and expense (per Boe of production):
Lease operating expenses	$	12.79	$	17.23		$	17.70		$	12.21		$	16.98		$	10.04
Production taxes		4.49		7.08			7.51			5.35			2.52			6.44
Depreciation, depletion and amortization				24.47			21.73			23.42			23.75			19.73
General and administrative expenses				18.60			13.64			13.12			13.32			11.86
Stock-based compensation expense(3)				—			—			—			—			17.54


(1)		The historical financial data for the six months ended June 30, 2007 have been derived from the audited statement of revenues and direct operating expenses for the properties acquired from Bill Barrett Corporation included elsewhere in this prospectus. Such statement does not reflect depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.

(2)		For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.

(3)		In March 2010, we recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests to certain employees of the company. See Note 9 to our unaudited consolidated financial statements.

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Lease Operating Expenses. Lease operating expenses increased $1.2 million to $3.0 million for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. This increase was primarily due to the higher number of productive wells from our Sanish and East Nesson acquisitions that were completed in the second and third quarters of 2009, respectively, and from the company’s well completions during 2009 and the first quarter of 2010. The 165% increase in oil volumes from the three months ended March 31, 2009 to the three months ended March 31, 2010 resulted in a 41% decrease in unit operating costs to $10.04 per Boe.

Production Taxes. Our production taxes for the three months ended March 31, 2010 and 2009 were 9.5% and 8.3%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the three months ended March 31, 2010 was higher than the production tax rate for the three months ended March 31, 2009 due to the increased weighting of oil revenues in North Dakota, which imposes an 11.5% production tax rate. The production taxes for the three months ended March 31, 2009 were primarily for oil and natural gas sales revenue associated with the properties in our West Williston project area that generate revenues that are subject to lower Montana production tax rates.

Depreciation, Depletion and Amortization (DD&A). Depreciation, depletion and amortization expense increased $3.3 million for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. The increase in DD&A expense for the three months ended March 31, 2010 was primarily due to the production increases from the Sanish and East Nesson acquisitions completed in the second and third quarters of 2009, respectively, and as a result of the company’s well completions during 2009 and the first quarter of 2010. The DD&A rate for the three months ended March 31, 2010 was $19.73 per Boe compared to $23.75 per Boe for the three months ended March 31, 2009. This decrease in the DD&A rate was due to the lower cost of reserve additions associated with the company’s 2009 acquisition and drilling activities.

Rig Termination. During 2008, we entered into drilling rig contracts with two drilling contractors. In the fourth quarter of 2008, we reduced our planned 2009 capital expenditure program and entered into discussions regarding early termination of these contracts. During the three months ended March 31, 2009, we paid a total of $3.0 million in rig termination expenses in connection with the termination of our remaining commitment under one drilling rig contract and the extension of the other drilling rig contract until June 2010. We did not have any rig termination expenses during the three months ended March 31, 2010.

Impairment of Oil and Gas Properties. During the three months ended March 31, 2010 and 2009, we recorded non-cash impairment charges of $3.1 million and $0.4 million, respectively, for unproved property leases that expired during the period. In determining the amount of the non-cash impairment charges for such periods, we considered the application of the factors described under “— Critical accounting policies and estimates — Impairment of unproved properties.”

Stock-based Compensation Expense. In the first quarter ended March 31, 2010, we recorded a $5.2 million non-cash charge for stock-based compensation expense associated with Oasis Petroleum Management LLC granting Class C Common Unit interests (“C Units”) to certain employees of the company. Based on the characteristics of the C Units awarded, we concluded that the C Units represented an equity-type award and accounted for the value of this award as if it had been awarded by the company. We used fair-value-based methods to determine the value of stock-based compensation awarded to our employees and recognized the

entire amount as expense due to the immediate vesting of the awards and no future requisite service period required by the employees. See Note 9 to our unaudited consolidated financial statements.

General and Administrative. Our general and administrative expenses increased to $3.5 million for the three months ended March 31, 2010 from $1.4 million for the three months ended March 31, 2009. This increase was primarily due to higher costs related to employee bonus compensation, additional employees and higher advisory, audit, legal and tax fees related to our initial public offering. As of March 31, 2010, we had 31 full-time employees compared to 21 employees as of March 31, 2009.

Derivatives. As a result of our derivative activities, we incurred cash settlement losses of $0.03 million for the three months ended March 31, 2010 and cash settlement gains of $1.4 million for the three months ended March 31, 2009. In addition, as a result of forward oil price changes, we recognized $0.4 million of unrealized mark-to-market non-cash derivative losses during the three months ended March 31, 2010 and $0.7 million of unrealized mark-to-market non-cash derivative losses during the three months ended March 31, 2009.

Interest Expense. Interest expense increased by $0.1 million for the three months ended March 31, 2010 compared to the three months ended March 31, 2009. Our lower weighted average outstanding debt balance and lower weighted average borrowing rates during the three months ended March 31, 2010, as compared to the three months ended March 31, 2009, was offset by the recognition of additional interest expense associated with entering into a new credit facility. We wrote off $0.1 million of remaining deferred financing costs associated with our previous revolving credit facility. Our weighted average debt balance decreased to $12.9 million for the three months ended March 31, 2010 compared to $19.7 million for the three months ended March 31, 2009.

Year ended December 31, 2009 compared to year ended December 31, 2008

Lease Operating Expenses. Lease operating expenses increased $1.6 million to $8.7 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. This increase was primarily due to the higher number of productive wells from our Sanish and East Nesson acquisitions that were completed in 2009. The 73% increase in oil volumes from 2008 to 2009 resulted in a 31% decrease in unit operating costs to $12.21 per Boe. The lease operating expenses for 2008 were also higher on a per barrel basis due to increased equipment repair and salt water disposal costs for the properties in our West Williston project area. Equipment repair costs were higher in 2008 due to the replacement and upgrading of equipment that had been deferred by the previous owner of the properties we acquired in 2007. Salt water disposal costs were higher in 2008 from the use of higher volume pumps resulting in increases of produced salt water volumes and the use of third-party salt water disposal facilities while we developed our own salt water disposal wells and centralized our salt water disposal facilities. As compared to the properties in our West Williston project area that produce primarily from the Madison formation, the properties we acquired in the Sanish acquisition produce primarily from the Bakken formation and have higher production volumes per well and lower per Boe operating costs than our Madison wells. The 2009 lease operating costs per Boe decreased in the West Williston project area due to our previously mentioned 2008 construction and centralization of our salt water disposal facilities.

Production Taxes. Our production taxes for the years ended December 31, 2009 and 2008 were 10.1% and 8.6%, respectively, as a percentage of oil and natural gas sales. The 2009 production tax rate was higher than the 2008 production tax rate due to the increased weighting of revenues in North Dakota which imposes an 11.5% production tax rate. The 2008 production taxes were primarily for oil and natural gas sales revenue associated with the properties in our West Williston project area acquired in 2007. A portion of the properties in our West Williston project area generate revenues that are subject to lower Montana production tax rates and certain North Dakota exemptions.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $8.0 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. The 2009 expense increase is primarily due to a 73% production increase from the 2009 East Nesson and Sanish acquisitions. The 2009 DD&A rate was $23.42 per Boe compared to $21.73 per Boe in 2008. The increase

from 2008 to 2009 was due to higher acquisition, leasehold, drilling and completion costs in the East Nesson and Sanish project areas.

Exploration Expenses. Exploration expenses of $1.0 million in the year ended December 31, 2009 were primarily composed of exploratory geological and geophysical costs. The comparable period in 2008 contained exploratory dry hole costs of $1.3 million and higher expenditures for exploratory geological and geophysical costs.

Rig Termination. During 2008, we entered into drilling rig contracts with two drilling contractors. In the fourth quarter of 2008, we reduced our planned 2009 capital expenditure program and entered into discussions regarding early termination of these contracts. In the first quarter of 2009, we paid a total of $3.0 million in rig termination expenses in connection with the termination of our remaining commitment under one drilling rig contract and the extension of the other drilling rig contract until June 2010. In November 2009, we entered into a new six-month drilling rig contract which replaced the contract we had previously extended.

Impairment of Oil and Gas Properties. During the years ended December 31, 2009 and 2008, we recorded $0.8 million and $45.5 million, respectively, in non-cash impairment charges on our proved oil and gas properties. The 2008 charges reflected the impact of significantly lower oil prices reflected in our 2008 reserve report.

During the years ended December 31, 2009 and 2008, we recorded non-cash impairment charges of $5.4 million and $1.6 million, respectively, for unproved property leases that expired during the period. In determining the amount of the non-cash impairment charges for such periods, we considered the application of the factors described under “— Critical accounting policies and estimates — Impairment of unproved properties,” including our 45,640 net leasehold acres that may expire in 2010 unless production is established from such acreage. As of December 31, 2009, we did not record an impairment charge with respect to any acreage expiring in 2010 based primarily on our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that would otherwise expire. Depending on the results of those activities, we may ultimately recognize in our 2010 financial statements impairment charges with respect to a portion of the $11.9 million carrying value associated with such acreage. In general, we would recognize $1.2 million of impairment expense for every 5,000 net leasehold acres that actually expire.

Gain on Sale of Properties. In December 2009, we sold our interests in non-core oil and natural gas producing properties located in the Barnett shale in Texas for $1.5 million. We recognized a gain of $1.4 million from the sale of these divested properties.

General and Administrative. Our general and administrative expenses increased to $9.3 million for the year ended December 31, 2009 from $5.5 million for the year ended December 31, 2008. This increase was primarily due to higher costs related to employee bonus compensation, additional employees and higher advisory, audit, legal and tax fees related to our initial public offering. As of December 31, 2009, we had 27 full-time employees compared to 20 employees as of December 31, 2008. On a per unit basis, general and administrative expenses were $13.12 per Boe compared to $13.64 per Boe for the years ended December 31, 2009 and 2008, respectively.

Derivatives. As a result of our derivative activities, we incurred cash settlement gains of $2.3 million for the year ended December 31, 2009 and cash settlement losses of $6.9 million for the year ended December 31, 2008. In addition, as a result of forward oil price changes, we recognized $7.0 million of unrealized mark-to-market non-cash derivative losses in 2009 and $14.8 million of unrealized mark-to-market non-cash derivative gains during 2008.

Interest Expense. Interest expense decreased $1.5 million, or 62%, for the year ended December 31, 2009 compared to the year ended December 31, 2008, due to a lower weighted average outstanding debt balance and

a lower weighted average interest rate during 2009. Our weighted average debt balance decreased to $22.8 million for the year ended December 31, 2009 compared to $37.7 million for the year ended December 31, 2008. The weighted average interest rate on our revolving credit facility borrowings was 3.5% for the year ended December 31, 2009 compared to 6.3% for the same period in 2008. At December 31, 2009 our outstanding debt balance under our revolving credit facility was $35.0 million with a weighted average interest rate of 2.95%.

Year ended December 31, 2008 compared to period from February 26, 2007 (Inception) through December 31, 2007

Lease Operating Expenses. Lease operating expenses increased $4.1 million for the year ended December 31, 2008 compared to the period from February 26, 2007 to December 31, 2007. The West Williston oil and natural gas producing properties were purchased in June 2007 and are reflected in only six months of our 2007 operating results as compared to a full twelve months in 2008. Lease operating expenses were $17.70 and $17.23 per Boe for the year ended December 31, 2008 and for the period from February 26, 2007 (inception) through December 31, 2007, respectively. The unit operating costs for the year ended December 31, 2008 were higher on a Boe unit basis due to increased equipment repair and salt water disposal costs for our West Williston properties. Equipment repair costs were higher in 2008 due to the replacement and upgrading of equipment that had been deferred by the previous owner of the properties we acquired in 2007. Salt water disposal costs were higher in 2008 from the use of higher volume pumps resulting in increases of produced salt water volumes and the use of third-party salt water disposal facilities while we developed our own salt water disposal wells and centralized our salt water disposal facilities. When comparing our lease operating expenses for the period from February 26, 2007 (inception) through December 31, 2007 to our predecessor’s lease operating expenses from January 1 through June 30, 2007, our lease operating expenses increased by $0.4 million or 14% to $2.9 million. The lease operating expense increase is primarily due to the increase in oil and gas operating and producing activities.

Production Taxes. Our production taxes for the year ended December 31, 2008, the period from February 26, 2007 (inception) through December 31, 2007 and our predecessor’s production taxes for the period from January 1 through June 30, 2007 were 8.6%, 8.8% and 8.5% respectively, of oil and natural gas sales for our West Williston oil and gas producing properties.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.5 million for the year ended December 31, 2008 compared to the period from February 26, 2007 to December 31, 2007. The West Williston oil and gas producing properties were purchased in June 2007 and are reflected in only six months of our 2007 operating results as compared to a full twelve months in 2008. The depreciation, depletion and amortization rate was $21.73 per Boe for the year ended December 31, 2008 as compared to $24.47 per Boe in the period from February 26, 2007 (inception) through December 31, 2007. The decrease in the per Boe rate from 2007 to 2008 was primarily due to the $45.5 million impairment charge that we recorded on our proved oil and gas properties as a result of lower crude oil prices at December 31, 2008. The decrease in the per Boe rate from the reduction in carrying value of our proved oil and gas properties was partially offset by the corresponding decrease in our proved reserve quantities as a result of lower crude oil prices at December 31, 2008.

Exploration Expenses. Exploration expenses of $3.2 million in the year ended December 31, 2008 included $1.3 million of dry hole costs with the remaining geological and geophysical costs comparable to those incurred from February 26, 2007 to December 31, 2007. For the period ended December 31, 2007, we did not incur any dry hole costs.

Impairment of Oil and Gas Properties. During the year ended December 31, 2008, we recorded a non-cash impairment charge of $45.5 million on our proved oil and gas properties as a result of lower crude oil prices at December 31, 2008, without a comparable charge for the period ended December 31, 2007. During the year ended December 31, 2008 and the period from February 26, 2007 to December 31, 2007, we recorded non-cash impairment charges of $1.6 million and $1.2 million, respectively, for unproved property leases that expired during the period.

General and Administrative. General and administrative expenses increased to $5.5 million for the year ended December 31, 2008 from $3.2 million during the period from February 26, 2007 through December 31,

2007. This increase was due both to a full 12 months of operations in 2008 as well as to the start-up nature of our activities in the 2007 period. General and administrative expenses were $13.64 per Boe for the year ended December 31, 2008 compared to $18.60 per Boe for the period ended 2007. The improvement was due to a full year of production volumes in the 2008 period versus only six months of volumes in the 2007 period.

Derivatives. In connection with the West Williston acquisition in June 2007, we entered into fixed-price swap and collar contracts. As a result, only five contract settlement periods occurred during the period from February 26, 2007 through December 31, 2007 as compared to twelve contract settlement periods for the year ended December 31, 2008. We incurred cash settlement losses of $6.9 million and $1.1 million during the year ended December 31, 2008 and the period from February 26, 2007 to December 31, 2007, respectively, on contract settlements of our crude oil derivative transactions. In addition, we recognized $14.8 million of unrealized mark-to-market non-cash derivative gains during the year ended December 31, 2008 as compared to $10.7 million of unrealized mark-to-market non-cash derivative losses during the period from February 26, 2007 through December 31, 2007 due to increases in forward oil prices during the 2008 period.

Interest Expense. Interest expense increased $0.6 million, or 35%, for the year ended December 31, 2008 compared to the period from February 26 through December 31, 2007, primarily due to our revolving credit facility borrowings being outstanding for a full 12 months in the 2008 period. The weighted average outstanding debt balance and weighted average interest rates were $37.7 million and 6.3% during for the year ended December 31, 2008. The weighted average outstanding debt balance and weighted average interest rates were $22.8 million and 7.81% during the period from February 26 through December 31, 2007.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from EnCap and other private investors, borrowings under our revolving credit facility and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our total 2010 capital expenditure budget is $220 million, which consists of:


	•	$134 million for drilling and completing operated wells;

	•	$45 million for drilling and completing non-operated wells;

	•	$15 million for maintaining and expanding our leasehold position;

	•	$5 million for constructing infrastructure to support production in our core project areas; and

	•	$21 million in unallocated funds which are available for additional drilling and leasing costs and activity.

While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2010 capital budget has been funded from a $35 million capital contribution from our equity investors in December 2009 and borrowings under our revolving credit facility. We believe the net proceeds from this offering together with cash flows from operations and additional borrowings under our revolving credit facility should be more than sufficient to fund the remainder of our 2010 and a portion of our 2011 capital expenditure budget. However, because the operated wells funded by our 2010 drilling plan represent only a small percentage of our gross identified operated drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.

On February 26, 2010, we entered into an amended and restated revolving credit facility, under which our initial borrowing base was $85 million. Upon the completion of this offering, our borrowing base will be reduced to $70 million. As of June 16, 2010 we had $75.0 million of indebtedness outstanding under our

revolving credit facility. For more information regarding our revolving credit facility, see “— Reserve-based credit facility.”

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “— Quantitative and Qualitative Disclosures About Market Risk.”

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Our cash flows for the period from February 26, 2007 through December 31, 2007, the years ended December 31, 2008 and 2009 and for the three months ended March 31, 2009 and 2010 are presented below (in thousands):


	Period from
	February 26, 2007			Year Ended						Three Months Ended
	(Inception) through			December 31,						March 31,
	December 31, 2007			2008			2009			2009			2010

Net cash provided by (used in) operating activities	$	2,284		$	13,766		$	6,148		$	(9,482	)	$	7,702
Net cash used in investing activities		(91,988	)		(78,478	)		(80,756	)		(12,509	)		(32,241	)
Net cash provided by (used in) financing activities		95,986			60,000			113,600			24,000			(13,413	)

Net change in cash	$	6,282		$	(4,712	)	$	38,992		$	2,009		$	(37,952	)

Cash flows provided by operating activities

Net cash provided by operating activities was $7.7 million for the three months ended March 31, 2010 and net cash used in operating activities was $9.5 million for the three months ended March 31, 2009. The increase in cash flows from operations was primarily the result of an increase in oil and natural gas production quarter over quarter and a $3.0 million rig termination payment made in March 2009.

Net cash provided by operating activities was $2.3 million for the period from February 26, 2007 through December 31, 2007, and $13.8 million and $6.1 million for the years ended December 31, 2008 and 2009, respectively. The increase in cash flows from operations for the year ended December 31, 2008 compared to period ended December 31, 2007 was primarily the result of an increase in oil and natural gas production. Cash flows from operations during the year ended December 31, 2009 decreased compared to 2008 primarily as a result of a $3.0 million rig termination payment and $3.9 million increase in general and administration expenses related to the initial public offering.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “— Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows used in investing activities

We had cash flows used in investing activities of $32.2 million and $12.5 million during the three months ended March 31, 2010 and 2009, respectively, as a result of our capital expenditures for drilling and development costs. For the three months ended March 31, 2009, our expenditures for the development of our properties were only for our West Williston project area and did not include our properties acquired in the Sanish and East Nesson project areas in June and September of 2009.

We had cash flows used in investing activities of $92.0 million during the period from February 26, 2007 through December 31, 2007 and we had $78.5 million and $80.8 million during the years ended December 31, 2008 and 2009, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The decrease in cash flows used in investing activities during the year ended December 31, 2008 compared to the period ended December 31, 2007 was attributable to the completion of the acquisition of the West Williston assets in 2007. The increase in cash used in investing activities for the year ended December 31, 2009 compared to 2008 of $2.3 million was attributable to our acquisitions of properties in the East Nesson and Sanish project areas, as well as increased levels of expenditures for the development of our properties.

Our capital expenditures for drilling, development and acquisition costs for the period from February 26, 2007 to December 31, 2007, the years ended December 31, 2008 and 2009 and the three months ended March 31, 2010 are summarized in the following table (in thousands):


	Period from						Three Months
	February 26, 2007		Year Ended				Ended
	(Inception) through		December 31,				March 31,
	December 31, 2007		2008		2009		2010

Project Area:
West Williston	$	95,109	$	12,703	$	15,521	$	11,472
East Nesson		—		66,513		40,208		15,617
Sanish		—		—		32,952		9,240
Other(1)		—		—		582		582

Total(2)	$	95,109	$	79,216	$	89,263	$	36,911


(1)		Represents data relating to our properties in the Barnett shale.

(2)		Consolidated capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our financial statements because amounts reflected in the table include changes in accounts payable from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.

Our board of directors has approved a total capital expenditure budget of $220 million for 2010, which is a 147% increase over the $89 million invested during 2009. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing $220 million for capital and exploration expenditures in 2010 as follows (in millions):


	Amount

Exploration and development drilling	$	179
Land costs		15
Infrastructure		5
Unallocated funds available for additional drilling and leasing costs and activity.		21

	$	220

Cash flows provided by financing activities

Net cash used in financing activities was $13.4 million for the three months ended March 31, 2010 and net cash provided by financing activities was $24.0 million for the three months ended March 31, 2009. For the three months ended March 31, 2010 and 2009, cash sourced through financing activities was primarily provided by capital contributions from EnCap and other private investors and borrowings under our revolving credit facility. Our long-term debt, including the current portion, was $23.0 million and $35.0 million at March 31, 2010 and December 31, 2009, respectively.

Net cash provided by financing activities was $96.0 million for period from February 26, 2007 through December 31, 2007, and $60.0 million and $113.6 million for the years ended December 31, 2008 and 2009, respectively. For the period from February 26, 2007 through December 31, 2007 and the years ended December 31, 2008 and 2009, cash sourced through financing activities was primarily provided by capital contributions from EnCap and other private investors and borrowings under our revolving credit facility. Our long-term debt, including the current portion, was $46.5 million, $26.0 million and $35.0 million at December 31, 2007, 2008 and 2009, respectively.

In March 2007, we entered into a limited liability company agreement that provided for an aggregate of $100 million in capital contribution commitments from EnCap, its affiliates and other investors, including certain members of management and other employees through Oasis Petroleum Management LLC. The original capital contribution commitment period extended from March 2007 until March 2010. In November 2007, the agreement was amended to increase the aggregate capital contribution commitment from $100 million to $200 million and to add additional members. In December 2009, the agreement was further amended to extend the commitment period to December 31, 2011 and increase the aggregate capital contribution commitment to $275 million. As of December 31, 2009, we had $40 million of remaining capital commitment capacity. This commitment will terminate upon the consummation of this offering.

Reserve-based credit facility

On February 26, 2010, we entered into an amended and restated reserve-based revolving credit facility under which our initial borrowing base was set at $85 million. Following the completion of this offering, our borrowing base will be $70 million with a maturity of February 26, 2014. At the earlier of the closing of this offering and October 1, 2010, the $15 million non-conforming portion of the borrowing base will terminate. The borrowing base under our revolving credit facility will be subject to redetermination on a semi-annual basis, effective April 1 and October 1, beginning October 1, 2010, and at up to one additional time per year, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The borrowing base will be determined by the administrative agent in its sole discretion and consistent with its normal oil and gas lending criteria in existence at that particular time. In addition, in the event that we elect to issue senior secured or unsecured notes (other than on a borrowing base redetermination date), our borrowing base will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such notes. Our revolving credit facility is available for our general corporate purposes, including, without limitation, working capital for exploration and production operations. Our obligations under our revolving credit facility are secured by substantially all of our assets. Our revolving credit facility is filed as an exhibit to the registration statement of which this prospectus is a part.

In connection with this offering, we will enter into an amendment to our revolving credit facility to add us as a guarantor under the facility and to allow for the corporate reorganization that will be completed simultaneously with the closing of this offering. For more information on the reorganization, see “Corporate Reorganization.”

As of June 16, 2010, we had $75.0 million outstanding under our revolving credit facility, the substantial majority of which was used to fund our drilling and acquisition activities. We anticipate that a portion of the net proceeds from this offering will be used to repay all of our borrowings outstanding as of the closing.

At our election, interest is generally determined by reference to:


	•	the London interbank offered rate, or LIBOR, plus an applicable margin between 2.25% and 4.00% per annum; or


	•	a domestic bank prime rate plus an applicable margin between 0.75% and 2.50% per annum.

Interest is generally payable quarterly for domestic bank rate loans and on the last day of the applicable interest period for LIBOR loans, but not less frequently than quarterly.

Our revolving credit facility contains various covenants that limit our ability to:


	•	incur indebtedness;

	•	grant certain liens;

	•	make certain loans, advances and investments;

	•	make dividends, distributions or redemptions;

	•	merge or consolidate;

	•	engage in certain asset dispositions, including a sale of all or substantially all of our assets;

	•	enter into certain transactions with affiliates;

	•	grant negative pledges or agree to restrict dividends or distributions from subsidiaries;

	•	allow gas imbalances, take-or-pay or other prepayments with respect to oil and gas properties that would require us from delivering hydrocarbons in the future in excess of an aggregate of 75,000 Mcfe; or

	•	enter into certain swap agreements.

Our revolving credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:


	•	a current ratio, consisting of consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash derivative assets and liabilities, as of the last day of any fiscal quarter; and

	•	a debt coverage ratio, consisting of consolidated debt (excluding non-cash obligations, accounts payable and other certain accrued liabilities) to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration expenses and other similar non-cash charges, minus all non-cash income added to consolidated net income, of not more than 4.0 to 1.0 for the four quarters ended on the last day of each fiscal quarter.

We believe that we are in compliance with the terms of our revolving credit facility. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:


	•	failure to pay any principal or any reimbursement obligation under any letter of credit when due or any interest, fees or other amount within certain grace periods;

	•	a representation or warranty is proven to be incorrect in any material respect when made;

	•	failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

	•	default by us on the payment of any other indebtedness in excess of $2.5 million, or any event occurs that permits or causes the acceleration of the indebtedness;

	•	bankruptcy or insolvency events involving us or our subsidiaries;

	•	the entry of, and failure to pay, one or more adverse judgments in excess of $2.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and

	•	a change of control, as defined in the credit agreement.

Obligations and Commitments

We have the following contractual obligations and commitments as of March 31, 2010 (in thousands):


	Payments Due by Period
			Less Than						More Than
Contractual Obligations	Total		1 Year		1 - 3 Years		3 - 5 Years		5 Years

Revolving credit facility(1)	$	23,000	$	—	$	23,000	$	—	$	—
Operating leases(2)		834		316		518		—		—
Drilling rig commitments(2)		5,050		5,050		—		—		—
Asset retirement obligations(3)		6,794		282		1,872		74		4,566

Total contractual cash obligations	$	35,678	$	5,648	$	25,390	$	74	$	4,566


(1)		Amount excludes interest on our revolving credit facility as both the amount borrowed and applicable interest rate is variable. On February 26, 2010, we entered into an amended and restated revolving credit facility, which matures on February 26, 2014. See Notes 7 and 11 to our audited consolidated financial statements.

(2)		See Note 10 to our audited consolidated financial statements for a description of lease obligations and drilling contract commitments.

(3)		Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 8 to our audited consolidated financial statements.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Method of accounting for oil and natural gas properties

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.

Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in the statement of operations in our consolidated financial statements. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this prospectus. The SEC’s revised rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (less than 12 month) contracts at market based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require

significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

Impairment of proved properties

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

Impairment of unproved properties

We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and records impairment expense for any decline in value.

We have historically recognized impairment expense for unproved properties at the time when the lease term has expired or sooner if, in management’s judgment, the unproved properties have lost some or all of their carrying value. We consider the following factors in our assessment of the impairment of unproved properties:


	•	the remaining amount of unexpired term under our leases;

	•	our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;

	•	our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

	•	our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

	•	our evaluation of the continuing successful results from the application of completion technology in the Bakken formation by us or by other operators in areas adjacent to or near our unproved properties.

The assessment of unproved properties to determine any possible impairment requires managerial judgment.

Asset retirement obligations

In accordance with the Financial Accounting Standard Board’s (FASB) authoritative guidance on asset retirement obligations, or ARO, we record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production

method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our consolidated statement of operations.

We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under Other Income (Expense) in our consolidated statement of operations.

Stock-based compensation

In March 2010, we recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests (“C Units”) to certain of our employees. The C Units were granted on March 24, 2010 to individuals who were employed as of February 1, 2010 and who were not executive officers or key employees with an existing capital investment in Oasis Petroleum Management LLC (“Oasis Petroleum Management LLC Capital Members”). All of the C Units vested immediately on the grant date and provide an opportunity for employees to participate in appreciation realized through a future sale of the company, an initial public offering of the company, and/or future sales or distributions of the company’s shares indirectly held by Oasis Petroleum Management LLC.

Based on the characteristics of the C Units awarded to employees, we concluded that the C Units represented an equity-type award and accounted for the value of this award as if it had been awarded by the company. The C Unit holders are entitled to receive a portion of the distributions made to Oasis Petroleum Management LLC, but only after those future distributions have satisfied a complete return of the capital investment previously made by the Oasis Petroleum Management LLC Capital Members, plus a specified return on their capital investment.

The C Units are membership interests in Oasis Petroleum Management LLC and not a direct interest in the company. The C Units are non-transferable and have no voting power. Oasis Petroleum Management LLC has an interest in OAS Holdco, but neither Oasis Petroleum Management LLC nor its members have a controlling interest or controlling voting power in OAS Holdco. Oasis Petroleum Management LLC will distribute any cash or common stock it receives to its members based on membership interests and distribution percentages. Oasis Petroleum Management LLC will only make distributions if it first receives cash or common stock from distributions made at the election of OAS Holdco.

Under the FASB’s authoritative guidance for share-based payments, stock-based compensation cost is measured based on the calculated fair value of the award on the grant date. The expense is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. We used a fair-value-based method to determine the value of stock-based compensation awarded to our employees and recognized the entire grant date fair value of $5.2 million as stock-based compensation expense due to the immediate vesting of the awards and no future requisite service period required of the employees.

We used a probability weighted expected return method to evaluate the potential return to and associated fair value allocable to the C Unit shareholders using selected hypothetical future outcomes (continuing

operations, private sale and an initial public offering). Approximately 95% of the fair value allocable to the C Unit holders comes from the initial public offering (“IPO”) scenario.

The IPO fair value of the C Units awarded to the company’s employees was estimated on the date of the grant using the Black-Scholes option-pricing model. The exercise price of the option used in the option-pricing model was set equal to the maximum value of Oasis Petroleum Management LLC’s current capital investment in the company as that value must be returned to Oasis Petroleum Management LLC Capital Members before distributions are made to the C Unit shareholders. Since we are not a public entity, we do not have historical stock trading data that can be used to compute volatilities associated with certain expected terms so the expected volatility value of 60% was estimated based on an average of volatilities of similar sized oil and gas companies with operations in the Williston Basin whose common stocks are publicly traded. Although the IPO is expected to occur in the near term there is no modeled distributable fair value that is allocable to the C Units as of March 31, 2010. The allocable fair value to the C Units occurs in an estimated timing of four years based on a future potential secondary offering or distribution of common stock of the company. The OAS Holdco agreement between its members does require a complete distribution of all remaining shares held by OAS Holdco in the fourth year following the year of the IPO event. The 2.08% risk-free rate used in the pricing model is based on the U.S. Treasury yield for a government bond with a maturity equal to the time to liquidity of four years. We did not estimate forfeiture rates due to the immediate vesting of the award and did not estimate future dividend payments as the company does not expect to declare or pay dividends in the foreseeable future.

Recent accounting pronouncements

Fair Value. In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements, and is effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We do not expect the adoption of this new guidance to have a significant impact on our financial position, cash flows or results of operations.

Oil and Gas Reporting Requirements. In December 2008, the SEC released the final rule, “Modernization of Oil and Gas Reporting,” which adopts revisions to the SEC’s oil and gas reporting disclosure requirements. The disclosure requirements under this final rule require reporting of oil and gas reserves using the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months rather than year-end prices, and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are allowed, but not required, to disclose probable and possible reserves in SEC filings. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. In January 2010, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. We have presented and applied this new guidance for the year ended December 31, 2009 herein.

Disclosures about Derivative Instruments and Hedging Activities. In March 2008, the FASB issued authoritative guidance related to disclosures about derivative instruments and hedging activities. Disclosures previously required only for the annual financial statements are now required in interim financial statements. This guidance is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows and to improve the transparency of the location and amounts of derivative instruments in a company’s financial statements and how they are accounted for. This guidance was

effective for us beginning January 1, 2009. The adoption of this guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.

Business Combinations. In December 2007, the FASB revised the authoritative guidance for business combinations, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. The revised guidance broadens the fair value measurement and recognition of assets acquired, liabilities assumed and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. The revised guidance also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases. Additionally, this guidance expands the required disclosures to improve the financial statement users’ abilities to evaluate the nature and financial effects of business combinations. The guidance is effective for business combinations for which the acquisition date is on or after January 1, 2009.

Internal Controls and Procedures

Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. As such, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. We have concluded that these control deficiencies constitute a material weakness in our control environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment, as described below.

In 2007, we did not maintain effective controls to ensure that correct working interests were used in our calculations of asset retirement obligations and depreciation, depletion and amortization expense. In 2008, the lack of effective controls over the accuracy of working interests and the accurate clearing of asset retirement obligations resulted in the misstatement of our proved property impairment expense. In 2009, we did not maintain effective controls over the accuracy of key spreadsheets used in our computations of unproved property impairment expense. For the three months ended March 31, 2010, we did not maintain adequate controls over changes to our DD&A rate calculation. For each of these periods, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2007, 2008, 2009 and the first quarter of 2010.

Although remediation efforts are still in progress, management has taken steps to address the causes of the 2007 and 2008 audit adjustments by putting into place new accounting processes and control procedures. Management created a centralized source for working interests and implemented controls to ensure that working interests used in reserve report information and accounting computations are reconciled to the centralized source of working interests. Management also implemented an account reconciliation and analysis process to ensure the correct recording of asset retirement obligations. In addition, management is in the process of evaluating the remediation steps needed to address the cause of the 2009 audit adjustment as well as the adjustment in the first quarter of 2010.

In January 2010, we hired a financial reporting manager and an operations accountant to allow for additional preparation and review time during our monthly accounting close process. During 2010, we expect to implement a comprehensive review of our internal controls, including our overall control environment, and to formalize our review and approval processes.

While we have begun the process of evaluating our internal control over financial reporting, we are in the early phases of our review and will not complete our review until well after this offering is completed. We

cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses, in addition to the material weaknesses previously identified. Management has taken steps to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the period from February 26, 2007 through December 31, 2007 and the years ended 2008 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.

We utilize derivative financial instruments (primarily swaps and zero-cost collars) to manage risks related to changes in oil prices. As of March 31, 2010, we utilized zero-cost collar options to reduce the volatility of oil prices on a significant portion of our future expected oil production.

We record all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

The following is a summary of our derivative contracts as of March 31, 2010:


		Total Notional		Average		Average		Fair
	Derivative	Amount of Oil		Floor		Ceiling		Value Asset
Settlement Period	Instrument	(Barrels)		Price		Price		(Liability)
								(In thousands)

2010	NYMEX Collar		422,686	$	69.15	$	90.38		(975	)
2011	NYMEX Collar		465,744	$	68.15	$	90.48		(2,167	)
2012	NYMEX Collar		38,418	$	68.07	$	90.56		(201	)

								$	(3,344	)

Interest rate risk. At December 31, 2009, we had indebtedness outstanding under our prior revolving credit facility of $35.0 million, which bore interest at floating rates. The weighted average annual interest rate incurred on this indebtedness for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007 was approximately 3.5%, 6.3% and 7.8%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the year ended December 31, 2009 would have resulted in an estimated $0.2 million increase in interest expense for the year ended December 31, 2009.

We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. See “Business — Marketing and Major Customers” for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility with investment grade ratings and we are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility which also carry investment grade ratings. Several of our significant customers for oil and gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

BUSINESS

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources. We have accumulated approximately 292,000 net leasehold acres in the Williston Basin, approximately 85% of which are undeveloped. We are currently focused on exploiting what we have identified as significant resource potential from the Bakken and Three Forks formations, which are present across a substantial majority of our acreage. A report issued by the USGS in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States. We believe the location, size and concentration of our acreage creates an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial experience in the Williston Basin. We have built our leasehold acreage position in the Williston Basin primarily through acquisitions in our three primary project areas, West Williston, East Nesson and Sanish. For a description of our acquisition activity, please see “—Our Acquisition History” below.


							2010 Budget											Average
			Identified Drilling								Drilling		Estimated Net					Daily
	Net		Locations				Gross		Net		Capex		Proved Reserves					Production
	Acreage		Gross		Net		Wells		Wells		(In millions)		MMBoe		% Developed			(Boe/d)(1)

Williston Basin
West Williston(2)		159,491		268		106.5		41		18.8	$	110		5.0		55	%		1,078
East Nesson(2)		124,004		113		57.0		13		7.4		47		3.9		36	%		1,037
Sanish(3)		8,747		88		9.6		37		3.8		22		4.3		32	%		1,084

Total Williston Basin		292,242		469		173.1		91		30.0		179		13.2		42	%		3,199
Other		879		—		—		—		—		—		0.1		100	%		96

Total		293,121		469		173.1		91		30.0	$	179		13.3		42	%		3,295


(1)		Represents average daily production for the three months ended March 31, 2010.

(2)		Identified gross and net drilling locations in our West Williston and East Nesson project areas are primarily comprised of Bakken wells based on 1,280-acre spacing and do not include any infill wells targeting the Bakken formation or any primary or infill wells targeting the Three Forks formation.

(3)		Identified gross and net drilling locations in our Sanish project area include a single Bakken infill well per 1,280-acre or 640-acre spacing unit (excluding spacing units already containing two Bakken producing wells) and include 10 gross (1.6 net) primary wells targeting the Three Forks formation.

Our total 2010 capital expenditure budget is $220 million, which consists of:


	•	$134 million for drilling and completing operated wells;

	•	$45 million for drilling and completing non-operated wells;

	•	$15 million for maintaining and expanding our leasehold position;

	•	$5 million for constructing infrastructure to support production in our core project areas; and

	•	$21 million in unallocated funds which are available for additional drilling and leasing costs and activity.

While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Our Acquisition History

We built our leasehold position in our West Williston, East Nesson and Sanish project areas through the following acquisitions and development activities:


	•	In June 2007, we acquired approximately 175,000 net leasehold acres in the Williston Basin with then-current net production of approximately 1,000 Boe/d. This acreage is the core of our West Williston project area.

	•	In May 2008, we entered into a farm-in and purchase arrangement, under which we earned or acquired approximately 48,000 net leasehold acres, establishing our initial position in the East Nesson project area.

	•	In June 2009, we acquired approximately 37,000 net leasehold acres with then-current net production of approximately 800 Boe/d, approximately 92% of which was from the Williston Basin. This acquisition consolidated our acreage in the East Nesson project area and established our Sanish project area.

	•	In September 2009, we acquired an additional 46,000 net leasehold acres with then-current net production of approximately 300 Boe/d. This acquisition further consolidated our acreage in the East Nesson project area.

Our Business Strategy

Our goal is to increase stockholder value by building reserves, production and cash flows at an attractive return on invested capital. We seek to achieve our goals through the following strategies:


	•	Aggressively Develop our Williston Basin Leasehold Position. We intend to aggressively drill and develop our acreage position to maximize the value of our resource potential. The aggregate 469 gross drilling locations that we have specifically identified in the Bakken formation in our three project areas will be our primary targets in the near term. Our 2010 drilling plan contemplates drilling approximately 35 gross (22.4 net) operated wells in these project areas by using two operated drilling rigs for the full year and adding up to three additional drilling rigs later in the year. Subject to market conditions and rig availability, we expect to operate up to seven drilling rigs in 2011, which could enable us to drill as many as 60 gross operated wells during that year. We believe we have the ability to add additional rigs this year if market conditions and program results warrant.

	•	Enhance Returns by Focusing on Operational and Cost Efficiencies. Our management team is focused on continuous improvement of our operating measures and has significant experience in successfully converting early-stage resource opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our project areas provides us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and fluid handling facilities and reducing the time and cost of rig mobilization.


	•	Adopt and Employ Leading Drilling and Completion Techniques. Our team is focused on enhancing our drilling and completion techniques to maximize recovery. We believe these techniques have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of techniques such as using longer laterals and more tightly spaced fracturing stimulation stages. We continuously evaluate our internal drilling results and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to evolve. This continued evolution may significantly enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.

	•	Pursue Strategic Acquisitions with Significant Resource Potential. In the near term, we intend to identify and acquire additional acreage and producing assets in the Williston Basin to supplement our existing operations. Going forward, we expect to selectively target additional domestic basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin. While we have no current intention to pursue international opportunities, our management team has significant international acquisition and operating expertise. If we identify an international opportunity with appropriate scale, risk and resource conversion potential, our board of directors may approve such an investment should they determine it is in the long-term best interest of our stockholders to do so.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:


	•	Substantial Leasehold Position in one of North America’s Leading Unconventional Oil-Resource Plays. Our current leasehold position of approximately 292,000 net leasehold acres in the Williston Basin is highly prospective in the Bakken formation. We believe our acreage is one of the largest concentrated leasehold positions in the basin prospective in the Bakken formation, and much of our acreage is in areas of significant drilling activity by other exploration and production companies. While we are initially targeting the Bakken formation, we are also evaluating what we believe to be significant prospectivity in the Three Forks formation which underlies a large portion of our acreage. We expect that the scale and concentration of our acreage will enable us to continue to improve our drilling and completion costs and operational efficiency.

	•	Large, Multi-Year Project Inventory. We have an inventory of approximately 469 gross drilling locations, primarily targeting the Bakken formation. We plan to drill 35 gross (22.4 net) operated wells across our West Williston and East Nesson project areas in 2010, the completion of which would represent 14% of our 246 gross identified operated drilling locations in these two project areas. We may be able to enhance the total recovery from the Bakken formation by drilling potential infill locations. In addition, our total number of drilling locations may also be substantially increased by pursuing the prospectivity we have identified in the Three Forks formation.

	•	Management Team with Proven Acquisition and Operating Skills. Our senior management team has extensive expertise in the oil and gas industry as previous members of management at Burlington Resources. The senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in other North American and international basins. See “Our Operations — Management Experience with Resource Conversion Plays and Horizontal Drilling Techniques.” We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, this team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs, and also has prior experience in the Williston Basin.

	•	Incentivized Management Team. Our management team will own a significant direct ownership interest in us immediately following the completion of this offering. In addition, our management team


		will also initially own an additional approximate 11% indirect economic interest in us through our controlling stockholder, OAS Holdco, which will own initially approximately 51% of our outstanding shares of common stock (or 45% if the underwriters’ over-allotment option is exercised in full) based on the initial public offering price of $14.00 per share. Our management team may significantly increase its sharing percentage in the shares held by OAS Holdco by increasing the return on investment for the other members of OAS Holdco. We believe our management team’s direct ownership interest immediately following the offering as well as their ability to increase their interest over time through OAS Holdco provides significant incentives to grow the value of our business for the benefit of all stockholders. See “Corporate Reorganization — LLC Agreement of OAS Holdco.”


	•	Operating Control over the Majority of our Portfolio. In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. We expect to operate 52% of our 469 identified gross drilling locations, or 83% of our 173.1 identified net drilling locations. As of December 31, 2009, approximately 59% of our total proved reserves were attributable to properties that we expect to operate. Approximately 75% of our estimated 2010 drilling and completion capital expenditure budget is related to operated wells, which we anticipate will result in an increase in 2010 of the percentage of our proved reserves attributable to properties we expect to operate. As of December 31, 2009, our average working interest in our operated and non-operated identified drilling locations was 58% and 14%, respectively. Controlling operations will allow us to dictate the pace of development as well as the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques.

Recent Developments

We had average daily production of 3,295 Boe per day during the three months ended March 31, 2010. Approximately 3,199 Boe per day, or 97% of the total, was produced from Williston Basin properties.

During the one month ended April 30, 2010, we had average daily production of 4,044 Boe per day.

Marketing and Transportation

transportation capacity for Williston Basin oil production could increase by 30,000 to 115,000 barrels per day by 2013, and we believe additional projects are under consideration. We sell a substantial majority of our oil production directly at the wellhead and are not responsible for its transportation. However, the price we receive at the wellhead is impacted by transportation and refining infrastructure constraints. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Risk Factors — Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.”

Our Operations

Estimated proved reserves

Unless otherwise specifically identified in this prospectus, the summary data with respect to our estimated proved reserves presented below has been prepared by our independent reserve engineering firms in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. As discussed below, the SEC has adopted new rules relating to disclosures of estimated reserves that are effective for fiscal years ending on or after December 31, 2009. In this prospectus, proved reserve estimates do not include any value for probable or possible reserves which may exist, categories which the new SEC rules would for the first time permit us to disclose in public reports. Our estimated proved reserves under the SEC rules in effect for the years ended December 31, 2007 and 2008 were determined using constant prices and unescalated costs based on the prices received and costs incurred on a field-by-field basis as of the year end. For the year ended December 31, 2009 and for future periods, our estimated proved reserves are determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-month prices, rather than year-end prices. For a definition of proved reserves under the SEC rules for both the fiscal years ending on or after December 31, 2009 and the fiscal years ending prior to December 31, 2009, see the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus. For more information regarding our independent reserve engineers, please see “— Independent petroleum engineers” below.

The table below summarizes our estimated proved reserves and related PV-10 at December 31, 2008 for each of our core operating areas as prepared consistent with the SEC’s rules regarding natural gas and oil reserve reporting in effect for fiscal years ending prior to December 31, 2009. The table also summarizes our estimated proved reserves and related PV-10 at December 31, 2009 for each of our project areas as prepared consistent with our and our independent reserve engineers’ interpretation of the SEC’s new rules. The SEC’s new rules relating to disclosures of estimated oil and natural gas reserves are effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month historical unweighted first-day-of-the-month average prices.

The reserve estimates at December 31, 2009 presented in the table below are based on a report prepared by DeGolyer and MacNaughton, independent reserve engineers. In preparing its report, DeGolyer and MacNaughton evaluated properties representing all of our PV-10 at December 31, 2009 under the new SEC rules. The reserve estimates at December 31, 2008 presented in the table below are based on a report prepared by W.D. Von Gonten & Co., independent reserve engineers. In preparing its report, W.D. Von Gonten & Co. evaluated properties representing all of our PV-10 at December 31, 2008 using the SEC rules in effect at the time of the report. For more information regarding our independent reserve engineers, please see

“— Independent petroleum engineers” below. The information in the following table does not give any effect to or reflect our commodity hedges.


	At December 31, 2008				At December 31, 2009
	Proved Reserves		PV-10(1)		Proved Reserves		PV-10
Project Area	(MMBoe)		(in millions)		(MMBoe)		(in millions)

Williston Basin
West Williston		2.2	$	16.4		5.0	$	50.7
East Nesson		0.1		1.3		3.9		31.6
Sanish		—		—		4.3		50.6

Total Williston Basin		2.3	$	17.7		13.2	$	132.9
Other(2)		—		—		0.1		0.6

Total		2.3	$	17.7		13.3	$	133.5


(1)		The PV-10 amount included in the report of W.D. Von Gonten & Co. at December 31, 2008 was $19.2 million because such amount does not give effect to additional estimated plugging and abandonment costs.

(2)		Represents data relating to our properties in the Barnett shale.

Estimated proved reserves at December 31, 2009 were 13.3 MMBoe, with a PV-10 of $133.5 million. Our estimated proved reserves at December 31, 2009 increased 11.0 MMBoe and PV-10 increased $115.8 million over our estimated proved reserves and PV-10 at December 31, 2008 due to the results of our drilling program, acquisitions and a higher oil price assumption at December 31, 2009.

The following table sets forth more information regarding our estimated proved reserves at December 31, 2007, 2008 and 2009:


	At December 31,
	2007			2008			2009

Reserve Data(1):
Estimated proved reserves:
Oil (MMBbls)		4.0			2.2			12.4
Natural gas (Bcf)		1.2			0.7			5.3
Total estimated proved reserves (MMBoe)		4.3			2.3			13.3
Estimated proved developed reserves:
Oil (MMBbls)		3.3			2.2			5.2
Natural gas (Bcf)		1.1			0.7			2.3
Total estimated proved developed reserves (MMBoe)		3.4			2.3			5.6
Percent developed		81	%		100	%		42	%
Estimated proved undeveloped reserves:
Oil (MMBbls)		0.8			—			7.2
Natural gas (Bcf)		0.2			—			3.0
Total estimated proved undeveloped reserves (MMBoe)		0.8			—			7.7
PV-10 (in millions)(2)	$	121.8		$	17.7		$	133.5
Standardized Measure (in millions)(3)		121.8			17.7			133.5


(1)		Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These


		prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

(2)		PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, our PV-10 and our Standardized Measure are equivalent because as of December 31, 2009, we were a limited liability company not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. However, in connection with the closing of this offering, we will merge into a corporation that will become a holding company for Oasis Petroleum LLC. As a result, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. The PV-10 amounts included in the reports of W.D. Von Gonten & Co. at December 31, 2007 and at December 31, 2008 were $122.9 million and $19.2 million, respectively, because the PV-10 amounts included in such reports do not give effect to additional estimated plugging and abandonment costs.

(3)		Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. In connection with the closing of this offering, we will merge into a corporation that will be treated as a taxable entity for federal income tax purposes. Future calculation of Standardized Measure will include the effects of income taxes on future net revenues. For further discussion of income taxes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Estimated proved reserves at December 31, 2009 were 13.3 MMBoe, a 477% increase from reserves of 2.3 MMBoe at December 31, 2008. Our 2009 estimated proved reserves increased 11.0 MMBoe over our 2008 estimated reserves due to acquisitions, our drilling program and higher oil price assumptions at December 31, 2009. Our commodity price assumption for oil increased $16.44 per Bbl to $61.04 per Bbl for the year ended December 31, 2009 from $44.60 per Bbl for the year ended December 31, 2008. Our proved developed producing reserves increased 3.3 MMBoe or 144% to 5.6 MMBoe for the year ended December 31, 2009 from 2.3 MMBoe for the year ended December 31, 2008 due to acquisitions and our drilling program. Our proved undeveloped reserves increased to 7.7 MMBoe for the year ended December 31, 2009 from 0.0 MMBoe for the year ended December 31, 2008 due to significant regional drilling activity, higher commodity price assumptions and higher overall estimated ultimate recoveries using recent drilling and completion techniques.

Estimated proved reserves at December 31, 2008 were 2.3 MMBoe, a 47% decrease from reserves of 4.3 MMBoe at December 31, 2007. Our estimated proved reserves decreased 2.0 MMBoe for the year ended December 31, 2008 from December 31, 2007 due primarily to lower commodity price assumptions. Our commodity price assumption for oil decreased $51.40 per Bbl to $44.60 per Bbl at December 31, 2008 from $96.00 per Bbl at December 31, 2007. Our proved developed producing reserves decreased 1.1 MMBoe or 33% to 2.3 MMBoe at December 31, 2008 from 3.4 MMBoe at December 31, 2007 due to commodity price assumptions and production. Our proved undeveloped reserves decreased from 0.8 MMBoe at December 31, 2007 to no proved undeveloped reserves at December 31, 2008 due to the effect of lower commodity price assumptions and drilling results in conventional reservoirs.

The PV-10 of our estimated proved reserves at December 31, 2009 was $133.5 million, a 653% increase from PV-10 of $17.7 million at December 31, 2008. Our PV-10 of estimated proved reserves increased $115.8 million over the 2008 PV-10 due to an increase in reserves and higher oil price assumptions.

The following table sets forth the estimated future net revenues, excluding derivatives contracts, from proved reserves, the present value of those net revenues (PV-10), and the expected benchmark prices used in projecting net revenues at December 31, 2007, 2008 and 2009 (in millions):


	At December 31,
	2007		2008		2009

Future net revenues	$	227.8	$	27.1	$	286.1
Present value of future net revenues:
Before income tax (PV-10)		121.8		17.7		133.5
After income tax (Standardized Measure)		121.8		17.7		133.5
Benchmark oil price(1)($/Bbl)	$	96.00	$	44.60	$	61.04


(1)		Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The PV-10 amounts included in the reports of W.D. Von Gonten & Co. at December 31, 2007 and at December 31, 2008 were $122.9 million and $19.2 million, respectively, because the PV-10 amounts included in such reports do not give effect to additional estimated plugging and abandonment costs.

Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2007 and 2008 are based on costs and prices in effect at December 31 of each year, without giving effect to derivative transactions, and are held constant throughout the life of the properties. Such calculations at December 31, 2009 are based on costs in effect at December 31, 2009 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, without giving effect to derivative transactions, and are held constant throughout the life of the properties. There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Independent petroleum engineers

Our estimated reserves and related future net revenues and PV-10 at December 31, 2009 are based on a report prepared by DeGolyer and MacNaughton, our independent reserve engineers, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and current guidelines established by the SEC. A copy of this report has been filed as an exhibit to the registration statement containing this prospectus. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary and Moscow. The firm’s more than 100 professionals include engineers, geologists, geophysicists, petrophysicists, and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, and equity studies related to the domestic and international energy industry. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 35 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974 and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. These services have been provided for over 70 years. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas, or mineral properties, or securities or notes of clients.

The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.

Our estimated reserves and related future net revenues and PV-10 at December 31, 2007 and 2008 are based on reports prepared by W.D. Von Gonten & Co., our independent reserve engineers at such dates, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. A copy of these reports have been filed as exhibits to the registration statement containing this prospectus. W.D. Von Gonten & Co. was formed in 1995 and is located in Houston, Texas. The firm has a professional staff consisting of thirteen petroleum engineers and three geophysicists and geologists, as well as a financial analyst and additional technical support. W.D. Von Gonten & Co. provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and reserve reports for both public and private companies. W.D. Von Gonten & Co. is a Texas Registered Engineering Firm.

Technology used to establish proved reserves

Under the new SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, DeGolyer and MacNaughton employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. For wells and locations targeting the Bakken formation, the evaluation included an assessment of the beneficial impact of the use of multi-stage hydraulic fracture stimulation treatments on estimated recoverable reserves. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and seismic data related to the Bakken formation were used to estimate original oil in place. In portions of our Sanish project area where estimated proved reserves were attributed to more than one well per spacing unit, the estimated original oil in place was used to calculate reasonable estimated recovery factors based on experience with similar reservoirs where similar drilling and completion techniques have been employed.

Internal controls over reserves estimation process

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Our Senior Vice President Asset Management is the technical person within the company primarily responsible for overseeing the preparation of our reserves estimates. Our Senior Vice President Asset Management has over 20 years of industry experience with positions of increasing responsibility in engineering and evaluations and holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Our Senior Vice President Asset Management reports directly to our Chief Operating Officer.

Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our Chief Operating Officer with representatives of our independent reserve engineers and internal technical staff. Following the consummation of this offering, we anticipate that our Audit Committee will conduct a similar review on an annual basis.

Production, revenues and price history

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2008 and through 2009. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the period from February 26, 2007 through December 31, 2007, for the years ended December 31, 2008 and 2009 and for the three months ended March 31, 2009 and 2010. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”


	Period from
	February 26, 2007		Year Ended				Three Months Ended
	(Inception) through		December 31,				March 31,
	December 31, 2007(1)		2008		2009		2009		2010

Operating data:
Net production volumes:
Oil (MBbls)		159		379		658		102		270
Natural gas (MMcf)		73		123		326		27		160
Oil equivalents (MBoe)		171		400		712		106		297
Average daily production (Boe/d)		929		1,092		1,950		1,183		3,295
Average sales prices:
Oil, without realized derivatives (per Bbl)	$	83.96	$	88.07	$	55.32	$	30.68	$	70.21
Oil, with realized derivatives(2) (per Bbl)		77.27		69.79		58.82		44.83		70.12
Natural gas (per Mcf)		6.25		10.91		4.24		3.29		7.02
Costs and expenses (per Boe):
Lease operating expenses	$	17.23	$	17.70	$	12.21	$	16.98	$	10.04
Production taxes		7.08		7.51		5.35		2.52		6.44
Depreciation, depletion and amortization		24.47		21.73		23.42		23.75		19.73
General and administrative expenses		18.60		13.64		13.12		13.32		11.86
Stock-based compensation expense(3)		—		—		—		—		17.54


(1)		For the period from February 26, 2007 through June 30, 2007, we did not engage in oil and gas operating or producing activities. Average daily production includes production from July 1, 2007 through December 31, 2007.


(2)		Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for hedge accounting.

(3)		In March 2010, we recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests to certain employees of the company. See Note 9 to our unaudited consolidated financial statements.

Net production volumes for the year ended December 31, 2009 were 712 MBoe, a 78% increase from net production of 400 MBoe for 2008. Our net production volumes increased 312 MBoe over 2008 net production volumes due to acquisitions and a successful operated and non-operated drilling and completion program. Our average oil sales prices, without the effect of realized derivatives, decreased $32.75 per Bbl to $55.32 per Bbl for the year ended December 31, 2009 from $88.07 per Bbl for the year ended December 31, 2008. Giving effect to our derivative transactions in both periods, our oil prices decreased only $10.97 per Bbl to $58.82 per Bbl for the year ended December 31, 2009 from $69.79 per Bbl for the year ended December 31, 2008. Our lease operating expenses decreased $5.49 per Boe, or 31%, to $12.21 per Boe for the year ended December 31, 2009 from $17.70 per Boe for the year ended December 31, 2008 due to acquisitions and our drilling program. The Bakken formation generally has a lower per unit lease operating cost than our conventional producing horizons.

Net production volumes for the year ended December 31, 2008 were 400 MBoe, a 134% increase from net production of 171 MBoe for the period from February 26, 2007 through December 31, 2007. Our 2008 net production volumes increased 229 MBoe over the 2007 net production volumes due to the initiation of our production activities on July 1, 2007. Our average oil sales prices, without the effect of realized derivatives, increased $4.11 per Bbl to $88.07 per Bbl for the year ended December 31, 2008 from $83.96 per Bbl for the period from February 26, 2007 through December 31, 2007. Giving effect to our derivative transactions in both periods, our oil prices decreased $7.48 per Bbl to $69.79 per Bbl for the year ended December 31, 2008 from $77.27 per Bbl for the period from February 26, 2007 through December 31, 2007. Our lease operating expenses increased $0.47 per Boe or 3% to $17.70 per Boe for the year ended December 31, 2008 from $17.23 per Boe for the period from February 26, 2007 through December 31, 2007 due to limited drilling program activities, rising operating costs and decreasing production per well.

The following table sets forth information regarding our average daily production during the three months ended December 31, 2009 and March 31, 2010:


							Average Daily Production for the
	Average Daily Production for the						Three Months Ended
	Three Months Ended December 31, 2009						March 31, 2010
	Bbls		Mcf		Boe		Bbls		Mcf		Boe

Williston Basin:
West Williston		1,036		420		1,106		998		481		1,078
East Nesson		1,005		65		1,016		996		243		1,037
Sanish		751		249		792		1,003		485		1,084

Total Williston Basin		2,792		734		2,914		2,998		1,210		3,199
Other		16		857		159		—		572		96

Total		2,808		1,591		3,073		2,998		1,782		3,295

Productive wells

The following table presents the total gross and net productive wells by project area and by oil or gas completion as of December 31, 2009:


	Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net

Williston Basin:
West Williston		130		45.5		—		—		130		45.5
East Nesson		43		19.0		—		—		43		19.0
Sanish		62		5.1		—		—		62		5.1

Total Williston Basin		235		69.6		—		—		235		69.6
Other		—		—		25		3.2		25		3.2

Total		235		69.6		25		3.2		260		72.8

Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2009 for each of our project areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.


	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net

Williston Basin
West Williston		31,305		19,482		214,417		140,009		245,722		159,491
East Nesson		26,361		16,969		176,430		107,035		202,791		124,004
Sanish		38,598		7,862		5,433		885		44,031		8,747

Total Williston Basin		96,264		44,313		396,280		247,929		492,544		292,242
Other		5,197		879		—		—		5,197		879

Total		101,461		45,192		396,280		247,929		497,741		293,121

Undeveloped acreage expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2009 that will expire over the next three years by project area unless production is established within the spacing units covering the acreage prior to the expiration dates:


	Expiring 2010				Expiring 2011				Expiring 2012
	Gross		Net		Gross		Net		Gross		Net

Williston Basin
West Williston		38,276		11,228		92,191		48,222		51,575		21,254
East Nesson		68,874		34,302		33,372		11,272		25,693		10,367
Sanish		1,038		110		1,154		65		120		21

Total Williston Basin		108,188		45,640		126,717		59,559		77,388		31,642
Other		—		—		—		—		—		—

Total		108,188		45,640		126,717		59,559		77,388		31,642

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. Based on our current drilling plans for 2010 and 2011, we expect to maintain through production approximately 15,200 of 45,640 net acres expiring in 2010 and 43,800 of 59,559 net acres expiring in 2011. Without giving effect to any drilling expenditures beyond our 2010 and 2011 drilling plans, we would expect to maintain through production approximately 17,500 of the 31,642 net acres expiring in 2012.

While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term. We believe that our leases are similar to our competitors’ fee lease terms as they relate to primary term and reserve royalty interests.

Drilling activity

The following table summarizes our drilling activity for the period from February 26, 2007 through December 31, 2007 and the years ended December 31, 2008 and 2009. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.


	2007				2008				2009
	Gross		Net		Gross		Net		Gross		Net

Development wells:
Oil		4		1.2		7		1.3		31		2.3
Gas		—		—		—		—		—		—
Dry(1)		2		1.5		1		1.0		—		—

Total development wells		6		2.7		8		2.3		31		2.3

Exploratory wells:
Oil		—		—		26		3.8		12		5.0
Gas		—		—		—		—		—		—
Dry(1)		—		—		1		0.3		—		—

Total exploratory wells		—		—		27		4.1		12		5.0

Total wells		6		2.7		35		6.4		43		7.3


(1)		Dry wells were drilled in conventional formations other than the Bakken.

As of December 31, 2009, there were 14 gross (2.7 net) development wells and 5 gross (1.4 net) exploratory wells in the process of drilling or completion.

Our drilling activity has increased each year since our inception. Exploration wells in 2008 and 2009 primarily focused on delineation and appraisal of the Bakken formation in our East Nesson and West Williston areas. Following the 2009 Kerogen acquisition, many operators increased the pace of development drilling in the Sanish project area, and as a result, we participated in a number of wells on a non-operated basis.

In 2007 and 2008, we had a total of 4 gross (2.9 net) wells that were deemed dry wells, all focused on conventional formations. In 2009 and in our 2010 capital plan, we have and expect to continue to be focused on drilling to the Bakken and Three Forks formations.

2010 capital expenditure budget

Our total 2010 capital expenditure budget is $220 million, which consists of:


	•	$134 million for drilling and completing operated wells;


	•	$45 million for drilling and completing non-operated wells;

	•	$15 million for maintaining and expanding our leasehold position;

	•	$5 million for constructing infrastructure to support production in our core project areas; and

	•	$21 million in unallocated funds which are available for additional drilling and leasing costs and activity.

While we have budgeted $220 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Our core project areas

Williston Basin

Our operations are focused in the Williston Basin in North Dakota and Montana. While we have interests in a substantial number of wells in the Williston Basin that target several different zones, our exploration and development activities currently are concentrated in the Bakken formation. Our management team originally targeted the Williston Basin because of its oil prone nature, multiple, stacked producing horizons, substantial resource potential and management’s previous professional history in the basin. The Williston Basin also has established infrastructure and access to materials and services. Regulatory delays are minimal in the Williston Basin due to fee ownership of properties, efficient state and local regulatory bodies and reasonable permitting requirements.

The entire Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada. The basin produces oil and natural gas from numerous producing horizons including, but not limited to, the Bakken, Three Forks, Madison and Red River formations. Commercial oil production activities began in the Williston Basin in the 1950’s with the first well drilled in 1953. Since then, an estimated 3.8 billion barrels have been produced from the basin, primarily from conventional oil accumulations, which can be found at depths ranging from 5,000 feet to 15,000 feet. The Williston Basin is now one of the most actively drilled unconventional oil resource plays in the United States with approximately 110 rigs drilling in the basin as of May 12, 2010, including 103 in North Dakota, six in Montana and one in South Dakota based on Anderson Reports’ weekly rig count. A report issued by the USGS in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States.

The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of three lithologic members including the upper shale, middle Bakken and lower shale. The formation ranges up to 150 feet thick. The upper and lower shales are highly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The middle Bakken, which varies in composition from a silty dolomite to shalely limestone or sand, also serves as a reservoir and is a critical component for commercial production. Generally, the Bakken formation is found at vertical depths of 8,500 to 11,500 feet.

Following the drilling of the first well in 1953, vertical well development of the Bakken formation occurred intermittently until 1987, when development of the upper shale using horizontal wells began to occur in the Bicentennial and Elkhorn Ranch areas. Development in the middle Bakken using horizontal wells began in 2001 with the discovery of the Elm Coulee Field. The use of horizontal drilling and improvements in completion technology have since expanded the development of the middle Bakken across a larger portion of the Williston Basin.

Generally, the reservoir rocks in the Bakken formation exhibit low porosity and permeability and require horizontal drilling and fracture stimulation technology in order to produce economically. The fracture stimulation techniques vary but most commonly utilize multi-stage mechanically diverted stimulations using un-cemented liners and packers. Completion techniques have evolved as the Bakken formation has developed, with operators generally increasing lateral length and fracture stimulation stages. Recent improvements in

completion techniques have increased costs by 20 to 40% on a normalized basis, but we believe they have also increased estimated ultimate recoveries of hydrocarbons by over 100% across a large portion of the Williston Basin based on our results to date as well as publicly available information for other operators in the basin. Based on our geologic interpretation of the Bakken formation, the evolution of completion techniques, our own drilling results as well as the publicly available drilling results for other operators in the basin, we believe that a substantial portion of our Williston Basin acreage is prospective in the Bakken formation and that the formation is the primary target for all of the well locations in our current drilling inventory.

The Three Forks formation generally found immediately under the Bakken formation has also proven to contain productive reservoir rock that may add incremental reserves to our existing leasehold positions. The Three Forks formation typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. The Three Forks formation is an unconventional carbonate play. Similar to the Bakken formation, the Three Forks formation has recently been exploited primarily using horizontal drilling and advanced completion techniques. Drilling in the Three Forks formation began in mid-2008 and a number of operators are currently drilling wells targeting this formation. Based on our geologic interpretation of the Three Forks formation and the evolution of completion techniques, we believe that much of our Williston Basin acreage is prospective in the Three Forks formation. However, there have been limited Three Forks tests on and around our acreage to date other than in our Sanish project area. As a result, we have not assigned drilling inventory to the Three Forks formation except for 10 gross (1.6 net) proved undeveloped wells in our Sanish project area.

Our total leasehold position in the Williston Basin as of December 31, 2009 consisted of 492,544 gross (292,242 net) acres (396,280 gross (247,929 net) undeveloped acres and 96,264 gross (44,313 net) developed acres). Our estimated net proved reserves in the Williston Basin were 13.2 MMBoe at December 31, 2009. Of our proved reserves in the Williston Basin, approximately 5.5 MMBoe were proved developed reserves, which are comprised of a combination of wells drilled to conventional reservoirs, Bakken wells drilled with older completion techniques and Bakken and Three Forks wells drilled with more recent completion techniques. Based on our results to date, we estimate that the Bakken and Three Forks wells drilled with more recent completion techniques will achieve estimated ultimate recovery rates that will in many cases more than double the ultimate recovery rates we expect from the Bakken wells with older completion techniques. Based on publicly available information for other operators in the basin, we believe this trend towards higher recovery rates is generally consistent across the basin. Of our proved reserves, 7.7 MMBoe were proved undeveloped reserves, all of which consisted of Bakken and Three Fork wells to be drilled with recent completion techniques. We expect that all of our identified drilling locations in each of our project areas will be drilled and completed using recent completion techniques.

As of December 31, 2009, we had a total of 69.6 net producing wells and net average daily production of 2,914 MBoe/d for the three month period ended December 31, 2009 in the Williston Basin. During this same three month period, our Bakken and Three Forks wells produced a net daily average of 2,018 Boe/d with 28.0 net producing wells on December 31, 2009. Accordingly, our 28 net Bakken and Three Forks wells were responsible for 69% of our average daily production during such period. Our working interest for all producing wells averages 30% and in the wells we operate is approximately 86%. As of January 1, 2010, we were drilling or completing 19 gross (4.1 net) wells in the Williston Basin. We participated in the drilling and completion of 43 gross wells for the year ended 2009.

Currently, we estimate our capital expenditures for 2010 will be $220 million, which includes drilling 35 gross (22.4 net) horizontal operated wells, numerous non-operated wells, construction of infrastructure to support production and leasehold acquisitions. Since most of this capital is expected to be spent on horizontal drilling in the Bakken and Three Forks formations, we expect that the proportion of our production from these formations will grow in the future. Accordingly, we expect our average net production per net producing well to similarly increase in the future. By using advanced completion techniques and longer laterals, the wells in the Bakken formation in our West Williston and East Nesson project areas we have recently participated in have produced at average gross oil rates of between or exceeding 350 to 700 barrels per day for the first 30 days of steady production and are expected to decline to between or exceeding 100 and 200 barrels per day

after 12 months of production. We believe that this production profile is comparable to that realized in other areas of the Williston Basin with similar geological characteristics and completion techniques.

Our Williston Basin activities are evaluated in three primary areas of operations, the West Williston area, the East Nesson area, and the Sanish area.

West Williston

The West Williston project area was our first area of operations and was established through an asset acquisition from Bill Barrett Corporation in June 2007. We control 245,722 gross (159,491 net) acres in the area, primarily in Williams and McKenzie counties in North Dakota and Roosevelt and Richland counties in Montana.

We had average daily production of 1,106 net Boe/d in the three months ended December 31, 2009, 19% of which was produced from the Bakken formation and the remainder from other conventional formations. As of December 31, 2009, we had an average working interest of 35% and operated 77% of our 45.5 net producing wells in the West Williston project area. Additionally, as of December 31, 2009, we had 268 gross (106.5 net) identified drilling locations based on 1280-acre spacing units, of which 83% are estimated to be operated by us, targeting the Bakken formation in the West Williston project area.

During the year ended 2009, we participated in the drilling and completion of 5 gross (1.3 net) horizontal Bakken wells in the West Williston project area. As of January 1, 2010, we were participating in drilling or completion of 4 gross (1.4 net) wells in the West Williston project area. We have budgeted $110 million in capital expenditures in the West Williston project area in 2010 for the drilling and completion of 41 gross (18.8 net) wells.

East Nesson

We expanded into the East Nesson project area through a farm-in transaction in May 2008 with Fidelity Exploration and Production Company and Kerogen Resources, Inc. We subsequently increased our working interests in the area through the acquisitions of assets from Kerogen Resources, Inc. and additional working interests from Fidelity Exploration in June and September 2009, respectively. We control 202,791 gross (124,004 net) acres in the area, primarily in Mountrail and Burke counties in North Dakota.

We had average daily production of 1,016 net Boe/d in the three months ended December 31, 2009, all of which was produced from the Bakken and Three Forks formations. As of December 31, 2009, we had an average working interest of 44% and operated 87% of our 19.0 net producing wells in the East Nesson project area. Additionally, as of December 31, 2009, we had 113 gross (57.0 net) identified drilling locations based almost entirely on 1280-acre spacing units, 95% of which are estimated to be operated by us, targeting the Bakken formation in the East Nesson project area.

During the year ended December 31, 2009, we drilled and completed 12 gross (4.1 net) horizontal Bakken and Three Forks wells in the East Nesson project area. As of January 1, 2010, we were drilling or completing 3 gross (2.0 net) wells in the East Nesson project area. We have budgeted $47 million in capital expenditures in the East Nesson project area in 2010 for the drilling and completion of 13 gross (7.4 net) wells.

Sanish

We expanded into the Sanish project area through the acquisition of assets from Kerogen Resources, Inc. in June 2009. We control 44,031 gross (8,747 net) acres in the area, all of which are located in Mountrail county in North Dakota.

We had average daily production of 792 net Boe/d in the three months ended December 31, 2009, all of which was produced from the Bakken and Three Forks formations. As of December 31, 2009, we had an average working interest of 8% in our 5.1 net wells in the Sanish project area. Additionally, as of December 31, 2009, we had 88 gross (9.6 net) identified drilling locations targeting the Bakken and Three Forks formations

in the Sanish project area. Our properties in the Sanish project area are entirely operated by other operators, the largest of which are Whiting Petroleum and Fidelity Exploration and Production Company.

During the year ended December 31, 2009, we participated in the drilling and completion of 26 gross (2.0 net) horizontal Bakken and Three Forks wells in the Sanish project area. As of January 1, 2010, we were participating in the drilling or completion of 12 gross (0.8 net) wells in the Sanish project area. We have budgeted $22 million in capital expenditures in the Sanish project area in 2010 for the drilling and completion of 37 gross (3.8 net) wells.

For more information on our reserves, operations and operating areas, see “Business — Our Operations.”

Other operating areas

Barnett Shale

As part of the Kerogen Resources asset acquisition in June 2009, we acquired approximately 3,000 net acres with then-current net production of approximately 140 Boe/d in the Barnett shale play in Texas. In December 2009, we sold a portion of the wells and acreage. As of December 31, 2009, our estimated proved reserves in the Barnett shale were approximately 111 MBoe, representing less than 1% of our PV-10 and were producing an average of 159 Boe/d for the three months ended December 31, 2009. We do not consider the Barnett shale a focus area and we do not currently plan any development activities in the area.

Management experience with resource conversion plays and horizontal drilling techniques

Our senior management team has extensive expertise in the oil and gas industry as previous members of management at Burlington Resources. Our senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in other North American and international basins. Specifically, our Chief Executive Officer, Chief Operating Officer or other of our executive officers were involved in the acquisition, operation or execution of a number of successful resource conversion plays, including Fruitland Coal, a coalbed methane development located in the San Juan Basin; Cedar Hills, a horizontal drilling development located in the Williston Basin; the Upper Bakken Shale, a horizontal drilling and development play located in the Williston Basin; tight gas sands developments in the San Juan Basin and Sichuan Basin; a basin-centered-gas resource conversion project located in the Western Canadian Sedimentary Basin; acquisitions of producing property and acreage in the Barnett Shale located in the Fort Worth Basin; and a coalbed methane development located in the Black Warrior Basin.

In addition, our senior management team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs, and also has prior experience in the Williston Basin, primarily while at Burlington Resources or its predecessors. At the time various members of our management team were at Burlington Resources, Burlington Resources was a significant lease and mineral holder in the Williston Basin. For example, Mr. Reid, our Chief Operating Officer, served in positions of varying responsibility including drilling engineer, drilling rig supervisor, asset manager and production superintendent with Burlington Resources in its Williston Basin operations over a six-year period from 1991 to 1997. Additionally, Mr. Beers, our Senior Vice President Land, held various land managerial positions in the Williston Basin for a ten-year period and Mr. Candito, our Senior Vice President Exploration, was a district geologist in the Williston Basin for a four-year period. While at Burlington Resources, various members of our management team also utilized horizontal drilling techniques extensively to develop reserves in multiple horizons. Much of Burlington Resources’ horizontal drilling activity during this period was in the Upper Bakken Black Shale and the Red River “B” horizons in the Williston Basin, where it drilled over 300 horizontal wells through the end of 1998.

Marketing and major customers

We principally sell our oil and natural gas production to marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is transported by truck to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the

effects of which cannot be accurately predicted. For a description of some of these factors, see “Risk Factors — Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production” and “Risk Factors — Delays and interruptions of production from our wells due to marketing and transportation constraints in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.”

In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows.

For the year ended December 31, 2008, sales to Tesoro Refining and Marketing Company and Texon L.P. accounted for approximately 57% and 14%, respectively, of our total sales. For the year ended December 31, 2009, sales to Tesoro Refining and Marketing Company and Texon L.P. accounted for approximately 32% and 30%, respectively, of our total sales. No other purchasers accounted for more than 10% of our total oil and natural gas sales for the year ended December 31, 2008 or 2009. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a number of alternative crude oil and natural gas purchasers in our producing regions.

We sell a substantial majority of our oil and condensate directly at the wellhead to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market based price, which incorporates regional differentials that include, but are not limited to, transportation costs and adjustments for product quality. Furthermore, we do not currently have any material oil and natural gas delivery commitments.

Crude oil produced and sold in the Williston Basin has historically sold at a discount to the price quoted for West Texas Intermediate (WTI) crude oil due to transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due to the production of oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation and refining capacity in the area. The last such period was the fall and winter of 2008 and 2009, when the Tesoro Refining and Marketing Company North Dakota Sweet discount to WTI on an average monthly basis reached $14.80 per barrel.

Since most of our oil and natural gas production is sold under market based or spot market contracts, the revenues generated by our operations are highly dependent upon the prices of and demand for oil and natural gas. The price we receive for our oil and natural gas production depends upon numerous factors beyond our control, including but not limited to seasonality, weather, competition, availability of transportation and gathering capabilities, the condition of the United States economy, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries, and domestic government regulation, legislation and policies. See “Risk Factors— A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.” Furthermore, a decrease in the price of oil and natural gas could have an adverse effect on the carrying value of our proved reserves and on our revenues, profitability and cash flows. See “Risk Factors— If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.”

Although we are not currently experiencing any significant involuntary curtailment of our oil or natural gas production, market, economic, transportation and regulatory factors may in the future materially affect our ability to market our oil or natural gas production. See “Risk Factors— Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.”

Title to Properties

As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties. See “Risk Factors — We may incur losses as a result of title defects in the properties in which we invest.”

Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt our drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Competition

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, including the acquisition of leasing options on oil and natural gas properties to the exploration and development of those properties. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for lease options on oil and natural gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Risk Factors — Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.”

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as

regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, or FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of transportation of oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index ceiling slightly, effective July 2001. Following the FERC’s five-year review of the indexing methodology, the FERC issued an order in 2006 increasing the index ceiling.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to

natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC. See below the discussion of “Other federal laws and regulations affecting our industry — Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. In order to provide respondents time to implement new regulations related to Order No. 704, the FERC has extended the deadline for calendar year 2009 until October 1, 2010. The report for calendar year 2010 and subsequent years remains May 1 of the following calendar year. Currently, Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. See below the discussion of “Other federal laws and regulations affecting our industry — FERC Market Transparency Rules.”

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case by case basis. To the extent that the FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is

of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Other federal laws and regulations affecting our industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005, or the EPAct 2005. EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of

price indices. In order to provide respondents time to implement new regulations related to Order No. 704, the FERC has extended the deadline for calendar year 2009 until October 1, 2010. The report for calendar year 2010 and subsequent years remains May 1 of the following calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Environmental, Health and Safety Regulation

Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the oil and gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and waste

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, CERCLA, also known as the Superfund law and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or

operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

Air emissions

The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our operations.

Climate change

In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic changes, the U.S. Congress has been actively considering legislation to reduce such emissions. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of “greenhouse gases” including carbon dioxide and methane that may contribute to warming of the Earth’s atmosphere and other climatic changes. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may

act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

In addition, on December 15, 2009, the EPA published its finding that emissions of greenhouse gases presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced a proposal to expand its final rule on greenhouse gas emissions reporting to include owners and operators of onshore oil and natural gas production. If the proposed rule is finalized in its current form, reporting of GHG emissions from such onshore production would be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to greenhouse gas emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

Water discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The Oil Pollution Act of 1990, as amended, or the OPA, which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S.

Endangered Species Act

The federal Endangered Species Act, as amended, the ESA, restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Employee health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended the OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other laws

The federal Energy Policy Act of 2005 amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDWA, to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering bills entitled the Fracturing Responsibility and Awareness of Chemicals Act, or the FRAC Act, to amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

Employees

As of May 31, 2010, we employed 35 people, including five employees in geology, 13 in operations and engineering, eight in accounting and finance and six in land. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

Offices

We currently lease approximately 13,500 square feet of office space in Houston, Texas at 1001 Fannin, Suite 202, where our principal offices are located. The lease for our Houston office expires in April 2012. We also have a lease for a field office in the Williston Basin in North Dakota.

Formation

We were incorporated in 2010 pursuant to the laws of the State of Delaware as Oasis Petroleum Inc. to become a holding company for Oasis Petroleum LLC after the reorganization. Oasis Petroleum LLC was formed as a Delaware limited liability company on February 26, 2007 by certain members of our senior management team through Oasis Petroleum Management LLC and private equity funds managed by EnCap.

MANAGEMENT

Directors, Executive Officers and Other Key Employees

The following table sets forth information regarding our directors and executive officers as of May 17, 2010. There are no family relationships among any of our directors or executive officers.


Name	Age		Title

Thomas B. Nusz		50	Chairman, President and Chief Executive Officer
Taylor L. Reid		47	Director, Executive Vice President and Chief Operating Officer
Michael McShane		56	Director
Douglas E. Swanson, Jr.		38	Director
Robert L. Zorich		60	Director
Kent O. Beers		60	Senior Vice President Land
Robert J. Candito		56	Senior Vice President Exploration
Michael H. Lou		35	Senior Vice President Finance
Roy W. Mace		51	Senior Vice President, Chief Accounting Officer and Corporate Secretary
H. Brett Newton		44	Senior Vice President Asset Management
Walter S. Smithwick		51	Senior Vice President Operations

The following table sets forth information regarding other key employees as of May 17, 2010.


Name	Age		Title

Steven C. Ellsberry		63	Vice President and Assistant Controller
Dean A. Gilbert		56	Vice President Development Geology
Thomas F. Hawkins		56	Vice President Land and Contracts
Robin E. Hesketh		51	Vice President Operations Engineering
Robert L. Stovall		53	Vice President Geophysics

Set forth below is the description of the backgrounds of our directors, executive officers and other key employees.

Thomas B. Nusz has served as our Director, President and Chief Executive Officer (or in similar capacities) since our inception in March 2007 and has 28 years of experience in the oil and gas industry. Mr. Nusz is currently serving as a member of our Nominating and Governance Committee and will become our Chairman upon the completion of this offering. From April 2006 to February 2007, Mr. Nusz managed his personal investments, developed the business plan for Oasis Petroleum LLC and secured funding for the company. He was previously a Vice President with Burlington Resources Inc., a formerly publicly traded oil and gas exploration and production company or, together with its predecessors, Burlington, and served as President International Division (North Africa, Northwest Europe, Latin America and China) from January 2004 to March 2006, as Vice President Acquisitions and Divestitures from October 2000 to December 2003 and as Vice President Strategic Planning and Engineering from July 1998 to September 2000 and Chief Engineer for substantially all of such period. He was instrumental in Burlington’s expansion into the Western Canadian Sedimentary Basin from 1999 to 2002. From September 1985 to June 1998, Mr. Nusz held various operations and managerial positions with Burlington in several regions of the United States, including the Permian Basin, the San Juan Basin, the Black Warrior Basin, the Anadarko Basin, onshore Gulf Coast and Gulf of Mexico. Mr. Nusz was an engineer with Mobil Oil Corporation and for Superior Oil Company from June 1982 to August 1985. He is a current member of the National Petroleum Council, an advisory committee to the Secretary of Energy of the United States. Mr. Nusz holds a Bachelor of Science in Petroleum Engineering from Mississippi State University.

Taylor L. Reid has served as our Director, Executive Vice President and Chief Operating Officer (or in similar capacities) since our inception in March 2007 and has 24 years of experience in the oil and gas industry. From November 2006 to February 2007, Mr. Reid worked with Mr. Nusz to form the business plan for Oasis Petroleum LLC and secure funding for the company. He previously served as Asset Manager Permian and Panhandle Operations with ConocoPhillips from April 2006 to October 2006. Prior to joining ConocoPhillips, he served as General Manager Latin America and Asia Operations with Burlington from March 2004 to March 2006 and as General Manager Corporate Acquisitions and Divestitures from July 1998 to February 2004. From March 1986 to June 1998, Mr. Reid held various operations and managerial positions with Burlington in several regions of the continental United States, including the Permian Basin, the Williston Basin and the Anadarko Basin. He was instrumental in Burlington’s expansion into the Western Canadian Sedimentary Basin from 1999 to 2002. Mr. Reid holds a Bachelor of Science in Petroleum Engineering from Stanford University.

Michael McShane has served as our director since May 2010 and is a member of our Audit Committee, Compensation Committee and Nominating and Governance Committee. Mr. McShane served as a director and President and Chief Executive Officer of Grant Prideco, Inc., a manufacturer and supplier of oilfield drill pipe and other drill stem products, from June 2002 until the completion of the merger of Grant Prideco with National Oilwell Varco, Inc. in April 2008, and Chairman of the Board of Grant Prideco from May 2003 through April 2008. Prior to joining Grant Prideco, Mr. McShane was Senior Vice President — Finance and Chief Financial Officer and director of BJ Services Company, a provider of pressure pumping, cementing, stimulation and coiled tubing services for oil and gas operators, from 1990 to June 2002. Mr. McShane has also served as a director of Complete Production Services, Inc. (NYSE: CPX), an oilfield service provider, since March 2007, Spectra Energy Corp (NYSE: SE), a provider of natural gas infrastructure, since April 2008, Globalogix, a privately held company that provides comprehensive services to upstream oil and gas producers and operators, since June 2007 and Triton LLC, an international company that designs, builds and supports a wide range of technologies and systems for subsea remote intervention operations and applications, since June 2009. Mr. McShane also serves as an advisor to Advent International, a global private equity firm.

Douglas E. Swanson, Jr. has served as our Director since our inception in March 2007 and is a member of our Audit Committee, Compensation Committee and Nominating and Governance Committee. Mr. Swanson has served as Managing Director of EnCap Investments L.P., an investment management firm, since 1999. Prior to his position at EnCap, he was in the corporate lending division of Frost National Bank from 1995 to 1997, specializing in energy-related service companies, and was a financial analyst in the corporate lending group of Southwest Bank of Texas from 1994 to 1995. Mr. Swanson has extensive industry experience serving on numerous boards of private oil and gas exploration and production companies over his 11-year history with EnCap and is a member of the Independent Petroleum Association of America and the Texas Independent Producers & Royalty Owners Association. Mr. Swanson holds a Bachelor of Arts in Economics and a Masters of Business Administration, both from the University of Texas at Austin.

Robert L. Zorich has served as our Director since our inception in March 2007 and is a member of our Audit Committee and Compensation Committee. Mr. Zorich is a Principal of EnCap Investments L.P., an investment management firm which he co-founded in 1988. Prior to the formation of EnCap, Mr. Zorich was a Senior Vice President of Trust Company of the West, a large, privately-held pension fund manager, from 1986 to 1988. Prior to joining Trust Company of the West, Mr. Zorich co-founded MAZE Exploration, Inc., a company actively involved in oil and gas exploration, development and reserve acquisitions, serving as its Co-Chief Executive Officer from 1981 to 1986. Mr. Zorich began his career at Republic National Bank of Dallas where he worked from 1974 to 1981. He ultimately served as Vice President and Division Manager in the Energy Department. He serves on the board of directors of several EnCap portfolio companies, is also a member of the board of directors of Enerplus Resources Fund (NYSE: ERF) and was previously a director of TODCO (NYSE: THE). He is a member of the Independent Petroleum Association of America and Texas Independent Producers and Royalty Owners Association. Mr. Zorich holds a Bachelor of Arts in Economics from the University of California at Santa Barbara and a Masters Degree in International Management from the American Graduate School of International Management.

Kent O. Beers has served as our Senior Vice President Land (or in similar capacities) since August 2007 and has 34 years of experience in the oil and gas industry. He previously served as Commercial Director International with ConocoPhillips from March 2006 to July 2006. Prior to joining ConocoPhillips, Mr. Beers held various managerial positions in the Commercial and Business Development divisions of Burlington from June 1997 to March 2006 and was Manager Corporate Divestitures of Burlington from June 1994 to May 1997. From June 1982 to May 1994, Mr. Beers held various land managerial positions with Burlington in the Rocky Mountain Region and the Williston Basin. Prior to joining Burlington, he was a Land Manager of NuCorp Energy Inc. from 1980 to 1982 and Regional Land Manager of Hunt Energy Corporation from 1976 to 1980. Mr. Beers holds a Bachelor of Science in Business Administration from Montana State University.

Robert J. Candito has served as our Senior Vice President Exploration (or in similar capacities) since our inception in March 2007 and has 32 years of experience in the oil and gas industry. He previously served as Principal Geologist with ConocoPhillips from April 2006 to August 2007. Prior to joining ConocoPhillips, Mr. Candito was a Senior Geological Advisor with Burlington from February 1995 to March 2006. At Burlington he held various positions in both exploration and development operations with Burlington in several regions of the continental United States, including the Gulf Coast, the Rocky Mountains and the Anadarko Basin. From January 1999 through March 2006, Mr. Candito worked for Burlington’s International Division on South American projects. Prior to joining Burlington, Mr. Candito worked for several independent operators in both the Rocky Mountain and Gulf Coast regions. Mr. Candito holds a Bachelor of Science in Geology from Bridgewater State College and a Master of Science in Geochemistry from the Colorado School of Mines.

Michael H. Lou has served as our Senior Vice President Finance (or similar capacities) since September 2009 and has 13 years of experience in the oil and gas industry. Prior to joining us, Mr. Lou was an independent contractor from January 2009 to August 2009. From February 2008 to December 2008, he served as the Chief Financial Officer of Giant Energy Ltd., a private oil and gas management company, from July 2006 to December 2008 he served as Chief Financial Officer of XXL Energy Corp., a publicly listed Canadian oil and gas company, and from August 2008 to December 2008, he served as Vice President Finance of Warrior Energy N.V., a publicly listed Canadian oil and gas company. From October 2005 to July 2006, Mr. Lou was a Director for Macquarie Investment Bank. Prior to joining Macquarie, Mr. Lou was a Vice President for First Albany Investment Banking from 2004 to 2006. From 1999 to 2004, Mr. Lou held positions of increasing responsibility, most recently as a Vice President, for Bank of America’s investment banking group. From 1997 to 1999, Mr. Lou was an analyst for Merrill Lynch’s investment banking group. Mr. Lou holds a Bachelor of Science in Electrical Engineering from Southern Methodist University.

Roy W. Mace has served as our Senior Vice President, Chief Accounting Officer and Corporate Secretary (or in similar capacities) since our inception in March 2007 and has 28 years of experience in the oil and gas industry. He previously served as Business Process Improvement & Integration Advisor with ConocoPhillips from March 2006 to March 2007. Prior to joining ConocoPhillips, Mr. Mace was a Senior Accounting Manager with Burlington from June 1999 to March 2006. Upon starting his career with Burlington as a Senior Corporate Auditor, Mr. Mace advanced into various managerial accounting positions at Burlington during the period from August 1986 to June 1999 . Prior to joining Burlington, Mr. Mace worked as an Assistant Controller for Permian Tank & Manufacturing from June 1984 to August 1986 and as a staff accountant for KPMG from July 1982 to June 1984. Mr. Mace holds a Bachelor of Business Administration and Accounting from Eastern New Mexico University and is a licensed Certified Public Accountant.

H. Brett Newton has served as our Senior Vice President Asset Management (or in similar capacities) since October 2007 and has 21 years of experience in the oil and gas industry. He previously served as Business Development and Partner Operations Manager Algeria with ConocoPhillips from April 2006 to September 2007. Prior to joining ConocoPhillips, Mr. Newton was Asset Manager North Africa with Burlington from May 2004 to March 2006 and held various engineering positions with Burlington from June 1994 to April 2004. Prior to joining Burlington, Mr. Newton worked for Chevron from January 1992 to June 1994. Mr. Newton has worked projects in several regions of the world, including the Berkine Basin (Algeria), the Permian Basin, the Green River Basin and the Williston Basin. Mr. Newton holds a Bachelor of Science from Texas A&M University and a Master of Science from the University of Texas at Austin, both in Petroleum Engineering.

Walter S. Smithwick has served as our Senior Vice President Operations (or in similar capacities) since October 2007 and has 26 years of experience in the oil and gas industry. He previously served as South Texas Operations Manager Lobo Field with ConocoPhillips from April 2006 to June 2007. Prior to joining ConocoPhillips, Mr. Smithwick was Asset Manager San Juan Basin with Burlington from May 2000 to April 2006 and Drilling Manager / Superintendent from October 1994 to May 2000. From 1986 to 1994, Mr. Smithwick held various operations and managerial positions with Burlington in several regions of the continental United States, including the San Juan Basin, Permian Basin and the Anadarko Basin. Prior to joining Burlington, Mr. Smithwick worked as a TC Unit Manager for Schlumberger from 1979 to 1981 and worked for Harkins Drilling Company in 1978. Mr. Smithwick holds a Bachelor of Science in Petroleum Engineering from Texas A&M University.

Steven C. Ellsberry has served as our Vice President and Assistant Controller (or in similar capacities) since September 2007 and has 26 years of experience in the oil and gas industry. Prior to joining us, Mr. Ellsberry was a consultant to energy businesses evaluating new acquisitions, integrating or divesting of oil and gas properties, building economic models for large gas gathering systems and assisting in our startup. At Burlington, Mr. Ellsberry had over 20 years of mergers and acquisitions experience responsible for due diligence, financial evaluations and back office integration. In addition, Mr. Ellsberry managed accounting, internal audit and information technology functions for Burlington. Mr. Ellsberry was a licensed Certified Public Accountant from 1988 to 2007 and holds a Bachelor of Science in Electrical Engineering from the University of Texas in Austin.

Dean A. Gilbert has served as our Vice President Development Geology (or in similar capacities) since September 2007. Prior to joining us, Mr. Gilbert was associated with The Scotia Group as Geoscience Manager from January 2001 to September 2007. In that capacity, he was involved in a variety of projects in the United States, both continental and offshore, as well as internationally. International areas included Mexico, South America, Indonesia and offshore West Africa. Prior to joining The Scotia Group, Mr. Gilbert held various geological positions with Burlington, Louisiana Land and Exploration and Union Texas Petroleum. He has over 33 years of geological and geophysical experience in the oil and gas industry. Mr. Gilbert holds a Bachelor of Arts degree in geology from Rice University in Houston.

Thomas F. Hawkins has served as our Vice President Land and Contracts (or in similar capacities) since March 2009 and has 32 years of experience in the oil and gas industry. Mr. Hawkins retired from ConocoPhillips Company in February 2009 after spending 31 years with ConocoPhillips and Burlington (which ConocoPhillips acquired in 2006). During that time, Mr. Hawkins held various operations and managerial positions in the Land, Marketing, Planning and Corporate Acquisitions and Divestitures groups. Mr. Hawkins has worked in several major regions in the continental United States, including the San Juan Basin in New Mexico, the Williston Basin and the Austin Chalk / Wilcox Trends in South Texas. Mr. Hawkins holds a Bachelor of Business Administration in Finance from the University of Texas at El Paso.

Robin E. Hesketh has served as our Vice President Operations Engineering (or in similar capacities) since April 2007 and has 29 years of experience in the oil and gas industry. Prior to joining us, he was a Principal Engineer with ConocoPhillips. He was the Drilling and Completions Manager with Burlington China from June 2004 to March 2006, and an Advisor Engineer with Burlington from 1993 to 2004 working in Corporate Acquisitions and Operations positions in various divisions. Prior to that, Mr. Hesketh worked in Operations engineering around the globe for British Gas and Hamilton Brothers Oil & Gas. He started his career with Sohio Alaska Petroleum Company working as a field engineer in Prudhoe Bay Alaska. Mr. Hesketh holds a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.

Robert L. Stovall has served as our Vice President Geophysics (or in similar capacities) since inception in March 2007 and has 27 years of experience in the oil and gas industry working both exploration and development projects. Prior to joining us, Mr. Stovall was Senior Geophysical Advisor at Apache Corporation in International New Ventures from September 2006 to March 2007. Mr. Stovall spent 11 years at Burlington with his last assignment being Senior Geophysical Advisor evaluating exploration, development, and new ventures in several Latin America countries, West Africa and China. Prior to that assignment, Mr. Stovall was responsible for Burlington projects in the Gulf of Mexico and the Anadarko Basin. Before joining Burlington

in 2006, Mr. Stovall spent 12 years at Conoco as a geophysicist covering projects in the Former Soviet Union, the North Sea, Australia, West Africa, and in the Portfolio Management Group. Mr. Stovall has a Master of Science degree from Virginia Tech and a Bachelor of Science Degree from the University of Montana. He is also a Certified Professional Geophysicist.

Board of Directors

Our board of directors currently consists of five members, including our President and Chief Executive Officer, our Executive Vice President and Chief Operating Officer, and two members designated by EnCap, which together with its affiliates controls a majority of the voting power of our outstanding common stock. Each of our current directors has significant industry experience.

Mr. McShane will serve as the chairman of our Audit Committee. We expect to add another independent director to our board of directors and Audit Committee within 90 days after the completion of this offering and a third independent director within one year after the completion of this offering. We also expect that our board will review the independence of our current directors using the independence standards of the NYSE and, based on this review, determine that Messrs. McShane, Swanson and Zorich are independent within the meaning of the NYSE listing standards currently in effect. As a result, we expect that our board of directors will consist of seven members within one year after the completion of this offering, five of whom will be independent. Because OAS Holdco will own a majority of our outstanding common stock following the completion of this offering, we will be a “controlled company” as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a “controlled company” may elect not to comply with certain NYSE corporate governance requirements, including: (1) the requirement that a majority of our board of directors consist of independent directors, (2) the requirement that our Nominating and Governance Committee be composed entirely of independent directors with a written charter addressing the Committee’s purpose and responsibilities, and (3) the requirement that our Compensation Committee be composed entirely of independent directors with a written charter addressing the Committee’s purpose and responsibilities. While these requirements will not apply to us as long as we remain a “controlled company,” as a result of the independent directors that we expect to add prior to and within one year following the completion of this offering, we expect that our board of directors will nonetheless consist of a majority of independent directors and that our Nominating and Governance Committee and Compensation Committee will consist entirely of independent directors. Our Nominating and Governance Committee and Compensation Committee each has a written charter addressing such committee’s purpose and responsibilities.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the company, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Following the completion of this offering, our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2011, 2012 and 2013, respectively. The Class I director is Mr. Swanson, the Class II directors are Messrs. Reid and Zorich and the Class III directors are Messrs. McShane and Nusz. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Committees of the Board of Directors

Our board of directors has an Audit Committee, Compensation Committee and Nominating and Governance Committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

The members of our Audit Committee are Messrs. McShane, Swanson and Zorich, each of whom our board of directors has determined is financially literate. Mr. McShane is the Chairman of this committee. Our board of directors has determined that Mr. McShane is the Audit Committee financial expert and is “independent” under the standards of the New York Stock Exchange and SEC regulations. We will rely on the phase-in rules of the SEC and NYSE with respect to the independence of our Audit Committee. These rules permit us to have an Audit Committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter.

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the Audit Committee will oversee our compliance programs relating to legal and regulatory requirements. We have adopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Compensation Committee

The members of our Compensation Committee are Messrs. Swanson, McShane and Zorich. Mr. Swanson is the Chairman of this committee. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our Compensation Committee will also administer our incentive compensation and benefit plans. We have adopted a Compensation Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Nominating and Governance Committee

The members of our Nominating and Governance Committee are Messrs. Swanson, McShane and Nusz. Mr. Swanson is the Chairman of this committee. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. We have adopted a Nominating and Governance Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

Compensation Committee Interlocks and Insider Participation

No member of our Compensation Committee has been at any time an employee of ours. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or Compensation Committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

To the extent any members of our Compensation Committee and affiliates of theirs have participated in transactions with us, a description of those transactions is described in “Certain Relationships and Related Party Transactions.”

Code of Business Conduct and Ethics

Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

EXECUTIVE COMPENSATION AND OTHER INFORMATION

Compensation Discussion and Analysis

This compensation discussion and analysis, or CD&A, provides information about our compensation objectives and policies for our principal executive officer, our principal financial officer and our other three most highly-compensated executive officers, and is intended to place in perspective the information contained in the executive compensation tables that follow this discussion. This CD&A provides a general description of our compensation program and specific information about its various components.

Throughout this discussion, the following individuals are referred to as the “Named Executive Officers” and are included in the Summary Compensation Table:


	•	Thomas B. Nusz, Chairman, President and Chief Executive Officer;

	•	Taylor L. Reid, Executive Vice President and Chief Operating Officer;

	•	Roy W. Mace, Senior Vice President, Chief Accounting Officer and Corporate Secretary;

	•	Kent O. Beers, Senior Vice President Land; and

	•	Walter S. Smithwick, Senior Vice President Operations.

Although this CD&A focuses on the information in the tables below and related footnotes, as well as the supplemental narratives relating to the last completed fiscal year, we also describe compensation actions taken before or after the last completed fiscal year to the extent such discussion enhances the understanding of our executive compensation disclosure. Contemporaneous with this offering, we anticipate making adjustments to our compensatory practices to be utilized in 2010 and later years that we believe will be more appropriate for a company with public stockholders. This CD&A discusses the compensatory practices in place during 2009 and highlights changes we will implement upon the consummation of this offering.

Compensation Program Philosophy and Objectives

Our future success and the ability to create long-term value for our stockholder depends on our ability to attract, retain and motivate the most qualified individuals in the oil and gas industry. Our compensation program is designed to reward performance that supports our long-term strategy and achievement of our short-term goals. We believe that compensation should:


	•	help to attract and retain the most qualified individuals in the oil and gas industry by being competitive with compensation paid to persons having similar responsibilities and duties in other companies in the same and closely related industries;

	•	align the interests of the individual with those of our stockholders and long-term value creation;

	•	be directly tied to the attainment of our annual performance targets and reflect individual contribution thereto;

	•	pay for performance, whereby an individual’s total compensation is heavily influenced by the company’s and individual’s performance; and

	•	reflect the unique qualifications, skills, experience and responsibilities of each individual.

Although not formally adopted as objectives in 2009 and prior years, the preceding objectives are consistent with the informal objectives we have employed historically.

Setting Executive Officer Compensation

From our inception in 2007 through 2009, the base compensation of our Named Executive Officers has remained relatively unchanged and was based largely on each executive officer’s base compensation level at prior positions, although some adjustments were made as we deemed necessary to maintain internal equity with respect to the compensation of all executive officers.

For 2010, Mr. Nusz, our Chief Executive Officer, and Mr. Reid, our Chief Operating Officer, have together reviewed our Named Executive Officers’ current compensation and have made a recommendation to our board of directors on overall compensation structure and individual compensation levels for each executive officer, including themselves, to be effective contemporaneous with this offering. Their recommendation was made based on the experience of Mr. Nusz and Mr. Reid in managing executives and establishing compensation, as well as the use of a peer group comparison. See “— Benchmarking and Peer Group” below. Our board of directors has approved this recommendation, which will become effective upon the consummation of this offering.

Our board of directors does not currently have a separate Compensation Committee due to the size of our existing board of directors and the lack of independent directors. However, upon consummation of this offering, our board of directors will have a Compensation Committee that will determine the compensation of our Named Executive Officers for future years. We currently expect that our Compensation Committee will generally target the 50th percentile for base salary and will target a higher 75th percentile for total compensation, subject to target performance metrics being satisfied. Although our Compensation Committee will review survey information as a frame of reference, ultimately the compensation decisions will be qualitative, not quantitative, and will take into consideration in material part factors such as the age of the data in the survey, the particular officer’s contribution to our financial performance and condition, as well as such officer’s qualifications, skills, experience and responsibilities. We expect outside factors to be considered as well, such as industry shortages of qualified employees for such positions, recent experience in the marketplace, and the elapsed time between the surveys used and our compensation decisions are made. Therefore, we expect that the final base salary of a particular officer may be greater or less than the 50th percentile and targeted total compensation may be greater or less than the 75th percentile.

Benchmarking and Peer Group. Historically, neither our board of directors nor our management has used peer group analysis or benchmarking for executive compensation purposes.

For 2010, our Chief Executive Officer, Chief Operating Officer, and Senior Vice President Finance met with representatives from Longnecker & Associates, our compensation consultant, to select a group of companies that they consider a “peer group” for executive compensation analysis purposes. This peer group was then used for purposes of developing the recommendations presented to our board of directors for compensation packages that will become applicable to our Named Executive Officers upon the closing of this offering. The oil and gas companies that comprise this peer group were selected primarily because they (i) have similar annual revenue, assets and market capitalization as us and (ii) potentially compete with us for executive talent. Longnecker & Associates compiled compensation data for the peer group from a variety of sources, including proxy statements and other publicly filed documents. Longnecker & Associates also provided published survey compensation data from multiple sources. This compensation data was then used to compare the compensation of our Named Executive Officers to comparably titled persons at companies within our peer group and in the survey data, generally targeting base salaries for our Named Executive Officers which are at the 50th percentile of our peer group, and targeting annual cash and long-term incentives so that our Named Executive Officers will have the opportunity to realize total compensation at the 75th percentile of our peer group based on both company and individual performance.

The 2010 peer group for compensation purposes consists of:


•	Abraxas Petroleum Corporation	•	GeoMet, Inc.
•	Approach Resources, Inc.	•	GMX Resources, Inc.
•	Arena Resources, Inc.	•	Goodrich Petroleum Corporation
•	Brigham Exploration Company	•	Gulfport Energy Corporation
•	Carrizo Oil and Gas, Inc.	•	Panhandle Oil & Gas, Inc.
•	Crimson Exploration, Inc	•	RAM Energy Resources, Inc.
•	Delta Petroleum Corporation	•	Rex Energy Corporation
•	Double Eagle Petroleum Company

Beginning in 2011, we anticipate that our Compensation Committee will review and re-determine annually the composition of our peer group so that the peer group will continue to consist of oil and gas exploration and production companies (i) with annual revenue, assets and market capitalization similar to us and (ii) who potentially compete with us for executive talent.

Role of the Compensation Consultant. From our inception through 2009, neither management nor our board of directors engaged a compensation consultant. For 2010, the company retained, independent of our board of directors, Longnecker & Associates as an independent compensation consultant to assist us in developing the non-employee director and executive compensation program to be implemented contemporaneously with this offering. Representatives from Longnecker & Associates have met with our board of directors and have advised the board of directors with regard to general trends in director and executive compensation matters, including (i) competitive benchmarking; (ii) incentive plan design; (iii) peer group selection; and (iv) other matters relating to executive compensation. In addition, Longnecker & Associates has provided our management with survey compensation data regarding our peer group. We anticipate that the charter of our Compensation Committee will grant the committee the sole authority to retain, at our expense, outside consultants or experts to assist it in its duties.

Elements of Our Compensation and Why We Pay Each Element

From our inception through 2009, our compensation program consisted of base salary and an annual performance-based cash bonus only. In addition, our Named Executive Officers and certain other employees have had the opportunity to invest their own funds in Oasis Petroleum Management LLC, which owns an interest in Oasis Petroleum LLC. See “Corporate Reorganization — Oasis Management LLC.” Following the consummation of this offering, we expect that the compensation program for our Named Executive Officers will be comprised of four elements: base salary, annual performance-based cash incentive awards, long-term equity-based compensation and other employee benefits.

Base Salary. Base salary is the fixed annual compensation we pay to each Named Executive Officer for performing specific job responsibilities. It represents the minimum income a Named Executive Officer may receive in any year. Contemporaneous with the consummation of this offering, we will implement salary increases for our Named Executive Officers in order to bring their base salaries in line with similarly titled executives at other companies within our peer group. For Named Executive Officers other than Messrs. Nusz and Reid, the salary increases are fairly small and ranged up to 11.4% of their fiscal 2009 salary. Mr. Beers will not receive a salary increase. Because of the increased responsibility of Messrs. Nusz and Reid with respect to our overall business and their greater experience with our company, we will increase their base salaries, upon the effectiveness of this offering as set forth in the following table:


					50^th Percentile		Percentage of 50^th
			2010 Base		of 2010 Peer		Percentile of
	2009 Base Salary		Salary(1)		Group		2010 Peer Group

Thomas B. Nusz	$	220,000	$	325,000	$	370,356		87.8	%
Taylor L. Reid		210,000		275,000		263,562		104.3


(1)		2010 base salaries will become effective upon consummation of this offering.

We believe the proposed salary increases for our Named Executive Officers are necessary in order for us to maintain a competitive compensation program following the effectiveness of this offering.

We will pay each Named Executive Officer a base salary in order to:


	•	recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace,

	•	remain competitive for executive talent within our industry,

	•	provide executives with sufficient, regularly-paid income, and

	•	reflect position and level of responsibility.

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In setting annual base salary amounts, we anticipate that our Compensation Committee will generally target by position the 50th percentile of our peer group.

Annual Performance-based Cash Incentive Awards. We have historically utilized, and expect to continue to utilize, performance-based annual cash incentive awards to reward achievement of performance goals to be specified for the company as a whole with a time horizon of one year or less.

We include an annual performance-based cash incentive award as part of our compensation program because we believe this element of compensation helps to:


	•	motivate management to achieve key shorter-term corporate objectives, and

	•	align executives’ interests with our stockholders’ interests.

Each year since our inception, our board of directors has approved annual performance incentive program targets based on metrics that it believes are relevant for a company of our size and growth expectations. These metrics were derived each year from our annual capital budgeting process based upon certain assumptions made by our management. The weight given to these targets and final bonus payments was discretionary during this period.

For 2009, the performance metrics used for purposes of our annual cash performance incentive program included production volumes, capital spending, lease operating expenses, Adjusted EBITDA and specified milestones relating to our short and long-term strategic objectives, including the successful execution of our business plan, securing capital, development and management of our project inventory and organizational improvements. The Named Executive Officers were each eligible to receive maximum annual incentive bonuses equal to 30% of their respective 2009 base salaries. The actual results we attained for 2009 significantly exceeded our targeted performance goals (for example, we targeted annual average daily production volumes at 1,193 Boe and attained 1,950 Boe). This is due in part to the completion of two acquisitions during 2009 that were not contemplated at the time our 2009 budget was set and that we drilled and participated in more wells during 2009 than planned in the original budget. As a result of the exceptional performance attained in 2009, each Named Executive Officer received the maximum bonus amount. In addition, each Named Executive Officer received a special cash performance bonus amount for fiscal 2009.

We have adopted the 2010 Annual Incentive Compensation Plan (the “Incentive Plan”) that will govern our annual cash performance incentive program for 2010 and later years, effective upon the consummation of this offering. For 2010, the annual performance incentive metrics include production growth, reserve growth and efficiency, cost structure (operating costs and general and administrative expenses), Adjusted EBITDA, and specified milestones relating to our short and long term strategic objectives, including the successful execution of our business plan, securing capital, development and management of our project inventory and organizational improvements. Certain broad categories such as “reserve growth and efficiency” and “cost structure” will include specific, quantifiable metrics to be consistent with the remaining categories. We have set threshold, target and maximum levels for the performance metrics which will serve as a guideline for setting the actual bonus amounts earned by the Named Executive Officers for 2010. In setting the performance incentive metrics for 2010, our board of directors conducted a historical analysis of the extent to which targets were met in prior years. Our performance goals serve more as guidelines for the board of directors to utilize throughout the year to ensure that our goals and targets will ultimately reflect our true performance. The performance goals are only one factor utilized by the board of directors, alongside a number of other subjective features, such as extenuating market circumstances, individual performance and safety performance when determining actual amounts of awards. We do not disclose our specific performance goals incorporated into our annual bonus plans on a prospective basis because we believe it would reveal sensitive information and cause competitive harm to our business. In addition, our board of directors retains the ability to apply discretion to awards based on extenuating market circumstances or individual performance and to modify amounts based on safety performance. In general, for our Named Executive Officers, our board of directors attempted to set objectives for 2010 such that there is approximately a 90% probability of achieving the threshold performance metric, a 60% probability of achieving the target performance metric and a 20% probability of achieving the maximum performance metric.

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If we achieve the target performance metric, the cash incentive awards are expected to be paid at target levels. In order to create additional incentive for exceptional company performance based on the metrics described above and the discretion of our board of directors, awards can be up to a maximum percentage of the base salary designated for each Named Executive Officer but it is not expected that payment at this level would occur in most years. For 2010, target awards to our two top executive officers, Mr. Nusz and Mr. Reid, are set at 80% and 60%, respectively, of 2010 base salary and may range from 40% to 160% of 2010 base salary, in the case of Mr. Nusz, and from 30% to 120% of 2010 base salary, in the case of Mr. Reid, depending on performance relative to specified performance metrics and subject to the discretion of our Compensation Committee. Target awards for the remaining Named Executive Officers are set at 50% of 2010 base salary and may range between 25% and 100% of 2010 base salary.

The target percentages for our annual performance-based cash incentive awards described above will become effective upon the consummation of this offering and will be in addition to special bonuses paid to our Named Executive Officers in February 2010. Messrs. Beers, Mace, Nusz, Reid and Smithwick received special bonuses of $86,726, $833, $460,413, $230,453 and $20,224, respectively. These special bonuses were paid at the sole discretion of our board of directors. While our Compensation Committee may make additional special bonuses in the future, there is currently no plan for any other such bonuses for 2010 or future periods, and we do not anticipate that special bonuses will be an element of our compensation program following the consummation of this offering.

Following the consummation of this offering, our Compensation Committee will determine an appropriate method of evaluating our company’s achievement relative to various performance metrics and will determine if the current categories and associated metrics should be adjusted for future fiscal years.

Long-Term Equity Based Incentives. Historically, our compensation structure has not included equity awards or other long-term incentive compensation, other than the opportunity of Named Executive Officers and other employees to invest their own funds in Oasis Petroleum Management LLC, which owns an interest in Oasis Petroleum LLC. This has allowed our Named Executive Officers to share in the benefits associated with our long-term growth. For 2010 and later years, we believe it is important and more consistent with the compensation programs of the companies in our peer group to establish a more formal long-term equity incentive program. As a result, we have adopted a Long-Term Incentive Plan, or LTIP, that permits the grant of our stock, options, restricted stock, restricted stock units, phantom stock, stock appreciation rights and other awards, any of which may be designated as performance awards or be made subject to other conditions, to our Named Executive Officers and other eligible employees in 2010 and later years. See “— Long-Term Incentive Plan.” Going forward, we believe that long-term equity-based incentive compensation will be an important component of our overall compensation program because it will:


	•	balance short and long-term objectives;

	•	align our executives’ interests with the long-term interests of our stockholders;

	•	reward long-term performance relative to industry peers;

	•	remain competitive from a total remuneration standpoint;

	•	encourage executive retention; and

	•	give executives the opportunity to share in our long-term performance.

Our Compensation Committee will have the authority under the LTIP to award incentive compensation to our executive officers in such amounts and on such terms as the committee determines appropriate in its sole discretion. Initially, our long-term equity based incentive compensation will consist of annual restricted stock awards; however, our Compensation Committee may determine in the future that different and/or additional award types are appropriate.

Beginning in fiscal 2010, we expect to award annual restricted stock awards. We believe this type of award, which will vest ratably over a three-year period provided the award recipient remains continuously employed through the vesting dates, aligns our executive officers with the interests of our stockholders on a long-term basis and has retentive attributes. The vesting of these awards will accelerate in full if the award recipient’s employment is terminated due to either death or disability, and the awards will be subject to the

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accelerated vesting provisions contained in any existing employment agreement or our Executive Change in Control and Severance Benefit Plan, to the extent an award recipient participates in the plan.

For 2010, our board of directors has approved target restricted stock awards for our two top executive officers, Mr. Nusz and Mr. Reid, which will be comprised of a number of shares with an aggregate value on the date of grant equal to 120% and 100%, respectively, of the officers’ 2010 base salaries. Awards for the remaining Named Executive Officers have been set at 75% of their respective 2010 base salaries.

In addition to the 2010 annual award grants, our board of directors has approved initial awards of an aggregate of 162,750 shares of restricted stock to executive officers and key employees, including the Named Executive Officers, upon consummation of this offering. The number of shares in each individual grant represents an aggregate value at grant date equal to approximately 100% of each individual’s post-IPO annualized base salary. These initial restricted stock awards will vest over three years with the initial one-third tranche vesting in January 2011, provided the award recipient remains continuously employed by us through each vesting date, and are subject to the same accelerated vesting provisions described above for the annual grants. The initial awards of restricted stock to executive officers and key employees, including the Named Executive Officers, are described in greater detail under “Principal and Selling Stockholders.”

Employee Benefits. In addition to the main elements of compensation previously discussed in this section, the Named Executive Officers are eligible for the same health, welfare and other employee benefits as are available to all our employees generally, which include medical and dental insurance, short and long-term disability insurance, a health club subsidy and a 401(k) plan with a dollar-for-dollar match on the first 5% of eligible employee contributions and escalating based on credited years of service. We do not sponsor any defined benefit pension plan or nonqualified deferred compensation arrangements at this time.

The general benefits offered to all employees (and thus to the Named Executive Officers) are reviewed by our board of directors each year. Following the consummation of this offering, we will provide our Named Executive Officers with financial planning assistance benefits that are not available to all other employees. In the future, we anticipate that benefits offered only to Named Executive Officers will be reviewed by the Compensation Committee in conjunction with its annual review of executive officer compensation.

How Elements of Our Compensation Program are Related to Each Other

We view the various components of compensation as related but distinct and emphasize “pay for performance” with a significant portion of total compensation reflecting a risk aspect tied to long- and short-term financial and strategic goals. Our compensation philosophy is to foster entrepreneurship at all levels of the organization by making long-term equity-based incentives, currently expected to be in the form of restricted stock grants, a significant component of executive compensation. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance. We have not adopted any formal or informal policies or guidelines for allocating compensation between long-term and currently paid out compensation, between cash and non-cash compensation, or among different forms of non-cash compensation. However, we believe that the compensation packages we will implement concurrently with the consummation of this offering are representative of an appropriate mix of compensation elements, and anticipate that our Compensation Committee will utilize a similar, though not identical, mix of compensation in future years. The approximate allocation of compensation elements in the proposed 2010 compensation packages for each Named Executive Officer is as follows:


							Other Named
	Thomas B. Nusz			Taylor L. Reid			Executive Officers

Base Salary		33.0	%		38.5	%		44.5	%
Annual Cash Incentive Bonus		27.0			23.0			22.0
Restricted Stock Awards		40.0			38.5			33.5

Total		100.0	%		100.0	%		100.0	%

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Accounting and Tax Considerations

Under Section 162(m) of the Internal Revenue Code of 1986, as amended, or the Code, a limitation was placed on tax deductions of any publicly-held corporation for individual compensation to certain executives of such corporation exceeding $1,000,000 in any taxable year, unless the compensation is performance-based. An exception applies to this deductibility limitation for a limited period of time in the case of companies that become publicly-traded.

We reserve the right to use our judgment to authorize compensation payments that do not comply with the exemptions in Section 162(m) when we believe that such payments are appropriate and in the best interest of the stockholders, after taking into consideration changing business conditions or the executive’s individual performance and/or changes in specific job duties and responsibilities. During 2009, the compensation level for none of our Named Executive Officers exceeded the tax deductible limitations under Section 162(m).

If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A of the Code, and such compensation does not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture and are subject to certain additional adverse tax consequences. We intend to design such arrangements to comply with Section 409A.

All equity awards to our employees, including executive officers, and to our directors will be granted and reflected in our consolidated financial statements, based upon the applicable accounting guidance, at fair market value on the grant date in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification, Topic 718, “Compensation — Stock Compensation.”

Employment Agreements

Contemporaneous with this offering, we will enter into employment agreements with Messrs. Nusz and Reid, effective as of the completion of this offering. These employment agreements are designed to ensure an individual understanding of how the employment relationship may be extended or terminated, the compensation and benefits that we provide during the term of employment and the obligations each party has in the event of termination of an officer’s employment. We expect the remainder of our employees to remain “at will.” In consultation with our compensation consultant, Longnecker & Associates, we determined that due to the historical roles they have played in the success and growth of the company, Messrs. Nusz and Reid are critical to the ongoing stability and development of the business and therefore, entering into employment agreements with these individuals is advisable.

The employment agreements provide for an initial three-year term that will be automatically renewed for successive one-year periods unless we give notice to the executive of non-renewal at least 60 days prior to the last day of the then-current term. The employment agreements provide that Messrs. Nusz and Reid will receive annual base salaries of $325,000 and $275,000, respectively, which may be increased by our board of directors in its discretion. The employment agreements also provide that Messrs. Nusz and Reid are eligible to receive annual performance-based bonuses each year during the employment term. The target amount of each annual bonus is 80% for Mr. Nusz and 60% for Mr. Reid of the executive’s base salary for the year, and greater or lesser amounts may be paid depending on the performance actually achieved. See “— Elements of Our Compensation and Why We Pay Each Element — Annual Performance-based Cash Incentive Awards.” The employment agreements also provide Messrs. Nusz and Reid with the opportunity to participate in the employee benefit arrangements offered to similarly situated executives and provide that they may periodically receive grants pursuant to our long-term incentive compensation plan.

The employment agreements provide for severance and change in control benefits to be paid to Messrs. Nusz and Reid under certain circumstances. The severance benefits are provided to reflect the fact that it may be difficult for executive officers to find comparable employment within a short period of time if they are involuntarily terminated. Change in control benefits are provided in order that the executives may objectively assess and pursue aggressively our interests and the interests of our stockholders with respect to a contemplated change in control, free from personal, financial and employment considerations. The employment agreements also impose certain non-compete, non-disclosure and similar obligations on the executives.

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The severance and change in control benefits and the post-termination obligations imposed on the executives are described in greater detail below. See “— Executive Compensation — Potential Payments Upon Termination and Change in Control.”

Severance and Change in Control Arrangements

Messrs. Nusz and Reid are currently parties to an Ancillary Agreement, dated as of March 5, 2007, pursuant to which they are entitled to receive certain severance benefits upon an involuntary termination without cause or for good reason. These severance benefits are described in greater detail below in the section entitled “— Executive Compensation — Potential Payments Upon Termination and Change in Control.” The Ancillary Agreement will terminate upon the consummation of this offering and will be of no further force or effect.

Other than the Ancillary Agreement entered into with Messrs. Nusz and Reid, we did not have any agreements in place providing severance or change in control benefits to our executive officers during 2009 and prior years. As described above, contemporaneous with the closing of this offering, the employment agreements will provide certain benefits and compensation to Messrs. Nusz and Reid in the event of certain terminations from employment, including in connection with a change in control. These benefits are described in greater detail above and in the section below entitled “— Executive Compensation — Potential Payments Upon Termination and Change in Control.”

For executive officers and other key employees other than Messrs. Nusz and Reid, our board of directors has adopted an Executive Change in Control and Severance Benefit Plan, to be effective as of the consummation of this offering, to provide severance and change in control benefits to participants following the consummation of this offering. We believe that adoption of the Executive Change in Control and Severance Benefit Plan is appropriate because we believe that the interests of our stockholders are best served if we provide separation benefits to eliminate, or at least reduce, the reluctance of executive officers and other key employees to pursue potential corporate transactions that may be in the best interests of our stockholders, but that may have resulting adverse consequences to the employment situations of our executive officers and other key employees. Further, this plan ensures an understanding of what benefits are to be paid to participants in the event of termination of their employment in certain specified circumstances and/or upon the occurrence of a change in control. The payments and benefits provided under the Executive Change in Control and Severance Benefit Plan are subject to compliance with certain post-employment obligations regarding the use of confidential and/or proprietary information and limiting the ability of participants to compete with us or solicit our employees or customers. The payments and benefits offered under the Executive Change in Control and Severance Benefit Plan are described in greater detail under “— Executive Compensation — Potential Payments Upon Termination and Change in Control.”

Gross-Ups. Under the employment agreements with Messrs. Nusz and Reid, and under our Executive Change in Control and Severance Benefit Plan in which the other Named Executive Officers will participate, if benefits to which the Named Executive Officers become entitled in connection with a change in control are considered “excess parachute payments” under Section 280G of the Code, then the Named Executive Officers would be entitled to an additional gross-up payment from us, unless the aggregate amount of the payments due to the executive in connection with a change in control may be reduced by 10% or less and fall within the safe harbor amount for Section 280G purposes such that no excise taxes are imposed, in which event, the payments to an executive will be so reduced. If a reduction of more than 10% would be needed in order for the payments to be within the Section 280G safe harbor, then no reduction in the payment amounts will be made and the executive will receive a gross-up payment in an amount such that, after payment by the Named Executive Officer of all taxes including any excise tax imposed upon the gross-up payment, the Named Executive Officer would retain an amount equal to the excise tax imposed upon the payment.

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Stock Ownership Guidelines

Stock ownership guidelines have not been implemented for our Named Executive Officers or directors. We will continue to periodically review best practices and reevaluate our position with respect to stock ownership guidelines.

Securities Trading Policy

Our securities trading policy provides that executive officers, including the Named Executive Officers, and our directors, may not, among other things, purchase or sell puts or calls to sell or buy our stock, engage in short sales with respect to our stock, buy our securities on margin, or otherwise hedge their ownership of our stock. The purchase or sale of stock by our executive officers and directors may only be made during certain windows of time and under the other conditions contained in our policy.

Executive Compensation

Summary Compensation Table

The following table shows information concerning the annual compensation for services provided to us by our Named Executive Officers during the fiscal year ended December 31, 2009.


							All Other
					Bonus		Compensation
Name and Principal Position	Year		Salary		(1)		(2)		Total

Thomas B. Nusz		2009	$	220,000	$	543,167	$	2,589	$	765,756
Chairman, President and Chief Executive Officer
Taylor L. Reid		2009		210,000		329,000		1,907		540,907
Executive Vice President and Chief Operating Officer
Roy W. Mace		2009		158,750		99,167		1,298		259,215
Senior Vice President, Chief Accounting Officer and Corporate Secretary
Kent O. Beers		2009		200,000		193,000		25,632		418,632
Senior Vice President Land
Walter S. Smithwick		2009		190,000		127,000		—		317,000
Senior Vice President Operations


(1)		Reflects amounts paid for services provided in fiscal year 2009 pursuant to annual performance targets reviewed and weighted at the direction of our board of directors. Also reflects cash amounts of $477,167, $266,000, $46,667, $133,000 and $70,000 paid to Messrs. Nusz, Reid, Mace, Beers and Smithwick, respectively, as one-time special performance bonuses for 2009 that were made in the sole discretion of our board of directors. While similar special bonuses were awarded in February 2010 and our compensation committee may make additional special bonuses in the future, there is currently no plan for any other such special bonuses for 2010 or future periods.

(2)		The following items are reported in the “All Other Compensation” column:


	Oasis Petroleum LLC
	All Other Compensation
	Year Ended December 31, 2009
							Rental		All Other
Employee	Health Club		Parking		Transit		Expenses		Compensation

Thomas B. Nusz	$	1,366	$	1,223	$	—	$	—	$	2,589
Taylor L. Reid		684		1,223		—		—		1,907
Roy W. Mace		750		—		548		—		1,298
Kent O. Beers		632		—		—		25,000		25,632
Walter S. Smithwick		—		—		—		—		—

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Discussion of Summary Compensation Table

Our executive compensation policies and practices, pursuant to which the compensation set forth in the Summary Compensation Table was paid or awarded, are described above in CD&A. As indicated therein, our executive compensation for 2009 consisted of a base salary, an annual performance based cash incentive award of up to 30% of base salary based on the performance of the company as a whole, a special 2009 cash performance bonus and limited additional compensation amounts.

Grants of Plan-based Awards and Outstanding Equity Awards at Fiscal Year End

None of our Named Executive Officers received any grants of plan-based awards in 2009 or held any outstanding equity awards as of December 31, 2009.

Pension Benefits

Other than our 401(k) Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.

Non-Qualified Deferred Compensation

We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.

Potential Payments Upon Termination and Change in Control

Other than the Ancillary Agreement that provides certain severance benefits to Messrs. Nusz and Reid upon an involuntary termination, there were no arrangements with our Named Executive Officers providing such individuals with severance or change in control benefits during 2009. The severance benefits Messrs. Nusz and Reid would have been entitled to receive under the Ancillary Agreement if they were involuntarily terminated at the end of fiscal 2009 are described in greater detail below.

Contemporaneous with the consummation of this offering, the Ancillary Agreement will terminate and the severance benefits provided in that agreement will cease to be representative of what our Named Executive Officers will be entitled to receive in the event they are terminated under certain circumstances or we undergo a change in control. As described above, effective as of the closing of this offering, we will enter into employment agreements with Messrs. Nusz and Reid that contain provisions regarding payments to be made to such individuals upon termination of their employment in certain circumstances, including in connection with a change in control. These agreements are described in greater detail below and under “Compensation Discussion & Analysis — Employment Agreements.” We have also adopted an Executive Change in Control and Severance Benefit Plan, to be effective as of the consummation of this offering, in which our Named Executive Officers, other than Messrs. Nusz and Reid, will participate. In order to provide our stockholders with an understanding of the severance and change in control benefits that will be implemented in connection with this offering, we also discuss below the benefits payable under the employment agreements and the Executive Change in Control and Severance Benefit Plan, assuming such arrangements were in place at the end of fiscal 2009.

Ancillary Agreement

Messrs. Nusz and Reid are parties to an Ancillary Agreement, dated as of March 5, 2007, that provides each of them with certain severance benefits in the event their employment is terminated. The Ancillary Agreement will cease to be in effect upon the completion of this offering. If the executive is terminated by us for “cause” or by the executive without “good reason,” the executive is entitled to receive his accrued but unpaid base salary and any expenses eligible for reimbursement. If the executive is terminated by us without “cause” or by the executive for “good reason,” the executive is also entitled to receive continued payment of his current base salary for a period of 18 months following the termination date. Assuming Messrs. Nusz and Reid were terminated without “cause” or for “good reason” effective December 31, 2009, the executives would

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have been entitled to receive aggregate payments of $330,000 and $315,000, respectively, payable in substantially equal installments over an 18-month period.

If Messrs. Nusz and Reid are terminated for any reason other than by us upon the occurrence of an “exit event,” the executive is required to comply with certain noncompete and other obligations specified in the Ancillary Agreement, provided we continue to pay the executive his salary for the next 18 months’ as severance. Specifically, the executives are required to comply with a noncompete covenant for 544 days following termination, a nondisclosure covenant for a two year period following termination, and a nonsolicitation covenant for 18 months following termination. These periods may be extended to account for any period of time during which an executive is in breach of the foregoing covenants.

For purposes of the Ancillary Agreement, the terms listed below have the following meanings:

(a) “cause” means (i) the breach by the executive of his duties that is materially detrimental to us and, if curable, that is not cured within 10 business days of notice of such breach, (ii) the executive’s failure to comply in any material respect with a lawful, written direction of the board of managers of Oasis Petroleum LLC reasonably related to the executive’s duties that he is physically able to perform, (iii) the executive’s conviction of, or plea of nolo contendere to, any felony, (iv) the commission of an act of fraud, dishonesty or moral turpitude that is reasonably likely to cause harm to us or our reputation, (v) the executive’s habitual insobriety or failure to perform his duties due to alcoholism or addiction to controlled substances, (vi) any action taken knowingly or with reckless disregard that is materially adverse to our interests or assets and (vii) a material breach by the executive of any of his covenants or agreements in the Ancillary Agreement or in the Oasis Petroleum LLC Agreement that, if curable, is not cured within five business days of notice of such breach.

(b) “exit event” means the sale of the company in one transaction or a series of related transactions, or structured as a sale or transfer of all or substantially all of the membership interests in the company (including by merger, consolidation, share exchange or similar transaction) or the sale or other transfer of all or substantially all of the assets of the company, or a combination of both.

(c) “good reason” means (i) the assignment to the executive of duties substantially inconsistent with his position, duties, responsibility and status, (ii) a reduction in the executive’s base salary or our failure to timely pay base salary, or any other material breach by us of our obligations under the Ancillary Agreement, (iii) relocation of the executive’s employment to a location other than the Houston, Texas metropolitan area for a material period of time, unless the executive consents or the relocation is necessitated by an act of God or certain other events, (iv) a person (with certain limited exceptions) acquires more than 50% of the voting securities of EnCap and more than two of the current partners of EnCap cease to be actively involved in the management and conduct of EnCap’s business and affairs, or (v) the EnCap members sell all or substantially all of their membership interests and cease to have designated managers to the board of managers of Oasis Petroleum LLC constituting a majority thereof.

Employment Agreements

Contemporaneous with the consummation of this offering, the Ancillary Agreement will terminate and the severance and change in control benefits due to Messrs. Nusz and Reid will be governed by the employment agreements. Under the employment agreements, upon any termination of employment, Messrs. Nusz and Reid are entitled to receive accrued but unpaid salary, any unpaid annual performance bonus earned for the calendar year prior to the year in which the executive terminates, reimbursement of eligible expenses and any employee benefits due pursuant to their terms. In addition, if Messrs. Nusz and Reid are terminated due to death or “disability,” then they will be entitled to receive the following amounts: (i) a pro-rata portion of the annual performance bonus for the calendar year of termination, (ii) an amount equal to 12 months’ worth of the executive’s base salary, payable in a lump sum within 60 days or by March 15 of the year following termination, whichever is earlier, and (iii) an amount equal to 18 months’ worth of COBRA premiums, if the executive elects and remains eligible for COBRA.

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If we terminate the employment of Messrs. Nusz and Reid for reasons other than “cause,” if we elect not to renew the employment agreement with the executive, or if the executives terminate employment for “good reason,” then Messrs. Nusz and Reid will be entitled to receive the following amounts: (i) a pro-rata portion of the annual performance bonus for the calendar year of termination, (ii) an amount equal to the greater of (a) the aggregate amount of base salary payable for the remainder of the employment term, and (b) an amount equal to 12 months’ worth of the executive’s base salary, payable in equal monthly installments (with amounts in excess of certain limitations under Section 409A of the Code payable in a lump sum within 60 days), (iii) an amount equal to 18 months’ worth of COBRA premiums, if the executive elects and remains eligible for COBRA, (iv) an amount equal to the aggregate of each annual target performance bonus the executive would have been entitled to receive if he had continued to perform services for the remainder of the employment term, if termination occurs during the initial three-year term, or an amount equal to 80% (for Mr. Nusz) and 60% (for Mr. Reid) of base salary for the remainder of the then-current term, if termination occurs after the initial term, in each case minus the amount of the pro-rata bonus paid, and (v) accelerated vesting of all outstanding equity awards. Severance amounts, other than the pro-rata bonus amount, are subject to the executive’s delivery to us (and nonrevocation) of a release of claims within 60 days of his termination date.

In the event a “change in control” occurs, all outstanding equity awards held by Messrs. Nusz and Reid will be immediately vested in full. In addition, in the event Messrs. Nusz and Reid are terminated by us other than for “cause,” if we elect not to renew the employment agreements or if the executives terminate employment for “good reason,” in each case, within 12 months following a “change in control,” Messrs. Nusz and Reid (or their respective estates) are entitled to receive (i) an amount equal to two times the sum of (a) the executive’s annualized base salary and (b) the maximum annual performance bonus he is eligible to receive for the then-current year if termination occurs during the initial three year term, or an amount equal to 80% (for Mr. Nusz) and 60% (for Mr. Reid) of base salary, if termination occurs after the initial term and (ii) an amount equal to 18 months’ worth of COBRA premiums, if the executive elects and is eligible to receive COBRA. If Messrs. Nusz and Reid are terminated in connection with a change in control and would receive greater benefits under another provision of their employment agreements, they will be entitled to receive the greater benefits. Because of the tax on so-called “parachute payments” imposed by the Code’s Section 4999 on payments made in connection with a change in control, we have agreed to reimburse Messrs. Nusz and Reid for any excise taxes imposed as a result of a payment of change in control benefits and to gross up those tax payments to keep the executives whole, unless the aggregate payments due to the executives may be reduced by 10% or less and, following such reduction, will not exceed the safe harbor amount under Code Section 280G, in which case the payments due will be so reduced.

Messrs. Nusz and Reid are subject to certain confidentiality, noncompete and nonsolicitation provisions contained in the employment agreements. The confidentiality covenants are perpetual, while the noncompete and nonsolicitation covenants apply during the term of the employment agreements and for 12 months following the employee’s termination date, except that the latter covenants will cease to apply if the executive is terminated for any reason on or after a change in control.

Executive Change in Control and Severance Benefit Plan

We have adopted an Executive Change in Control and Severance Benefit Plan that, upon the consummation of this offering, will provide severance and change in control benefits to our Named Executive Officers (other than Messrs. Nusz and Reid). Participants in the Executive Change in Control and Severance Benefit Plan will be entitled to receive, upon any termination of their employment, accrued but unpaid base salary, any unpaid annual performance bonus earned for the calendar year prior to the year in which the participant’s employment is terminated, reimbursement of eligible expenses and any employee benefits due pursuant to their terms. In addition, if a participant in the Executive Change in Control and Severance Benefit Plan is terminated due to death or “disability,” then the participant will be entitled to receive the following amounts: (i) a pro-rata portion of the annual performance bonus for the calendar year of termination, (ii) an amount equal to 12 months’ worth of the participant’s base salary, payable in a lump sum, and (iii) an amount equal to 18 months’ worth of COBRA premiums, if the participant elects and remains eligible for COBRA.

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If we terminate the employment of a participant in the Executive Change in Control and Severance Benefit Plan for a reason other than “cause” or if a participant terminates employment for “good reason,” then the participant will be entitled to receive the following amounts: (i) a pro-rata portion of the annual performance bonus for the calendar year of termination, (ii) an amount equal to 12 months’ worth of the participant’s base salary, payable in 12 equal monthly installments, (iii) an amount equal to 18 months’ worth of COBRA premiums, if the participant elects and remains eligible for COBRA, and (iv) accelerated vesting of all outstanding equity awards. Severance amounts, other than the pro-rata bonus amount, are subject to the participant’s delivery to us (and nonrevocation) of a release of claims within 60 days of the termination date.

In the event a “change in control” occurs, all outstanding equity awards held by participants in the Executive Change in Control and Severance Benefit Plan will be immediately vested in full. In addition, in the event a participant is terminated by us other than for “cause” or if the participant terminates employment for “good reason,” in each case, within 24 months following a “change in control,” the participant (or his or her estate) is entitled to receive (i) an amount equal to two times the sum of (a) the participant’s annualized base salary and (b) the participant’s target performance bonus for the calendar year in which the “change in control” occurs, and (ii) an amount equal to 18 months’ worth of COBRA premiums, if the participant elects and remains eligible for COBRA. If the employment of a participant in the Executive Change in Control and Severance Benefit Plan is terminated in connection with a “change in control” and the participant would receive greater benefits under another provision of the Executive Change in Control and Severance Benefit Plan, the participant will be entitled to receive the greater benefits. Because of the tax on so-called “parachute payments” imposed by Code Section 4999 on payments made in connection with a change in control, we have agreed to reimburse participants in the Executive Change in Control and Severance Benefit Plan for any excise taxes imposed as a result of a payment of change in control benefits and to gross up those tax payments to keep the participants whole, unless the aggregate payments due to the executives may be reduced by 10% or less and, following such reduction, will not exceed the safe harbor amount under Code Section 280G, in which case the payments will be so reduced.

Participants in the Executive Change in Control and Severance Benefit Plan are subject to certain confidentiality, noncompete and nonsolicitation provisions contained in the plan. The confidentiality provisions are perpetual, while the noncompete and nonsolicitation covenants apply while a participant is employed by us and for 12 months following the participant’s employment termination date, except that the latter covenants will cease to apply if the participant is terminated for any reason on or after a change in control.

Under our 2010 Annual Incentive Compensation Plan, upon the occurrence of a “change in control,” participants (including our Named Executive Officers) will receive the target annual cash bonus award amount that the participant is eligible to earn for the calendar year in which the “change in control” occurs, payable within 30 days after the date of the “change in control.”

For purposes of the employment agreements, the Executive Change in Control and Severance Benefit Plan and the 2010 Annual Incentive Compensation Plan, the terms listed below are defined as follows:

(i) “cause” means (a) the executive has been convicted of a misdemeanor involving moral turpitude or a felony, (b) the executive has engaged in grossly negligent or willful misconduct in performing his duties, which has a material detrimental effect on the company, and (with respect to participants in the Executive Change in Control and Severance Benefit Plan) which acts continued for a period of 30 days after notice of such failure of performance, (c) the executive has breached a material provision of the employment agreement or the plan, as applicable, (d) the executive has engaged in conduct that is materially injurious to us or (e) the executive has committed an act of fraud. Messrs. Nusz and Reid will have a limited period of 30 days to cure events (unless the cause event is that described in clause (a) above).

(ii) “change in control” means (a) a person acquires 50% or more of our outstanding stock or outstanding voting securities, subject to certain limited exceptions, (b) individuals who serve as board members on the effective date of the employment agreements or the plan, as applicable (or who are subsequently approved by a majority of such individuals), cease for any reason to constitute at least a majority of the board of directors, (c) consummation of a reorganization, merger, consolidation or a sale

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of all or substantially all of our assets, subject to certain limited exceptions, or (d) approval by our stockholders of a complete liquidation or dissolution.

(iii) “disability” means the executive’s inability to perform the executive’s essential functions with or without reasonable accommodation, if required by law, due to physical or mental impairment.

(iv) “good reason” means, without the executive’s express written consent, (a) a material breach by us of the employment agreement or of our obligations under the plan, as applicable, (b) a material reduction in the executive’s base compensation, (c) a material diminution in the executive’s authority, duties or responsibilities, (d) a change in the geographic location where executive must normally perform services by more than 50 miles or (e) requirement that the executive report to an employee instead of to our board (for Mr. Nusz) or a material reduction in the authority, duties or responsibilities of the person to whom the executive reports (for all other Named Executive Officers). The executive must notify us within 60 days of the occurrence of any such event and we have 30 days following notice to cure.

Quantification of Payments

The table below discloses the amount of compensation and/or benefits due to the Named Executive Officers in the event of their termination of employment and/or in the event we undergo a change in control. The amounts disclosed assume such termination and/or the occurrence of such change in control was effective December 31, 2009, but taking into account the severance and change in control arrangements described above that will be entered into or adopted contemporaneously with the consummation of this offering (except that any accelerated vesting associated with equity awards is not included in the table since no such awards were outstanding and our stock was not publicly traded on December 31, 2009). The amounts below constitute estimates of the amounts that would be paid to the Named Executive Officers upon their respective terminations and/or upon a change in control under such arrangements. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a Named Executive Officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered “forward-looking statements.”


							Termination
			Termination				without Cause or
	Termination		due to		Termination		for Good Reason		Change
	due to Death or		Non-Extension		without Cause or		Following a		in
Named Executive Officer	Disability		by Company		for Good Reason		Change in Control		Control

Thomas B. Nusz
• Salary(1)	$	220,000	$	220,000	$	220,000		—		—
• Bonus Amounts(1)		66,000		66,000		66,000	$	66,000	$	66,000
• COBRA Premiums(2)		27,924		27,924		27,924		27,924		—
• Change in Control Payments(3)		—		—		—		572,000		—
• Total(4)	$	313,924	$	313,924	$	313,924	$	665,924	$	66,000

Taylor L. Reid
• Salary(1)	$	210,000	$	210,000	$	210,000		—		—
• Bonus Amounts(1)		63,000		63,000		63,000	$	63,000	$	63,000
• COBRA Premiums(2)		27,924		27,924		27,924		27,924		—
• Change in Control Payments(3)		—		—		—		546,000		—
• Total(4)	$	300,924	$	300,924	$	300,924	$	636,924	$	63,000

Roy W. Mace
• Salary(1)	$	175,000		—	$	175,000		—		—
• Bonus Amounts(1)		52,500		—		52,500	$	52,500	$	52,500
• COBRA Premiums(2)		27,924		—		27,924		27,924		—
• Change in Control Payments(3)		—		—		—		455,000		—
• Total(4)	$	255,424		—	$	255,424	$	715,822	$	52,500

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							Termination
			Termination				without Cause or
	Termination		due to		Termination		for Good Reason		Change
	due to Death or		Non-Extension		without Cause or		Following a		in
Named Executive Officer	Disability		by Company		for Good Reason		Change in Control		Control

Kent O. Beers
• Salary(1)	$	200,000		—	$	200,000		—		—
• Bonus Amounts(1)		60,000		—		60,000	$	60,000	$	60,000
• COBRA Premiums(2)		18,647		—		18,647		18,647		—
• Change in Control Payments(3)		—		—		—		520,000		—
• Total(4)	$	278,647		—	$	278,647	$	577,050	$	60,000

Walter S. Smithwick
• Salary(1)	$	190,000		—	$	190,000		—		—
• Bonus Amounts(1)		57,000		—		57,000	$	57,000	$	57,000
• COBRA Premiums(2)		27,924		—		27,924		27,924		—
• Change in Control Payments(3)		—		—		—		494,000		—
• Total(4)	$	274,924		—	$	274,924	$	578,924	$	57,000


(1)		Based on rate of salary and annual bonus opportunity in effect for each Named Executive Officer as of December 31, 2009.

(2)		Reflects 18 months’ worth of the COBRA premiums at the following monthly rates: $1,551.35 for Mr. Nusz, $1,551.35 for Mr. Reid, $1,551.35 for Mr. Mace, $1,035.93 for Mr. Beers, and $1,551.35 for Mr. Smithwick.

(3)		For the year ended December 31, 2009, 30% of base salary was the only performance bonus opportunity that our Named Executive Officers were eligible to receive under our annual incentive plan, so it is treated as both the target and the maximum bonus for purposes of these calculations.

(4)		For Messrs. Nusz, Reid and Smithwick none of the total payment amounts reported above exceed their respective Code Section 280G safe harbor amounts, so no reduction or gross up of these amounts have been reflected. The aggregate severance amount reported as payable to Mr. Mace following a change in control includes a gross up payment of $180,398 because the amount otherwise payable to him pursuant to the terms of the Executive Change in Control and Severance Benefit Plan exceeds his Code Section 280G safe harbor amount and would need to be reduced by more than 10% in order to fall within the Code Section 280G safe harbor. The aggregate severance amount reported as payable to Mr. Beers following a change in control has been reduced by $21,597 to fall within his Code Section 280G safe harbor limit in accordance with the terms of the Executive Change in Control and Severance Benefit Plan as described above.

Long-Term Incentive Plan

We expect to adopt a LTIP prior to the consummation of this offering in order to attract and retain the best available personnel for positions of substantial responsibility, to provide additional incentives to our employees, directors and consultants, and to promote the success of our business. We anticipate that the LTIP will primarily provide for grants of (a) incentive stock options qualified as such under U.S. federal income tax laws, (b) stock options that do not qualify as incentive stock options, (c) stock appreciation rights, or SARs, (d) restricted stock awards, (e) restricted stock units (f) performance awards, or (g) any combination of such awards.

The LTIP is not subject to the Employee Retirement Income Security Act of 1974, as amended, or ERISA. The LTIP, for a limited period of time following this offering, will qualify for an exception to the deductibility limitations imposed by Section 162(m) of the Code. As a result, during that limited period of time, awards will be exempt from the limitations on the deductibility of compensation that exceeds $1,000,000.

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Shares Available. The maximum aggregate number of shares of our common stock that may be reserved and available for delivery in connection with awards under the LTIP is 7,200,000, subject to adjustment in accordance with the terms of the LTIP. If common stock subject to any award is not issued or transferred, or ceases to be issuable or transferable for any reason, including stock subject to an award that is cancelled, forfeited or settled in cash and shares withheld to pay the exercise price of or to satisfy the withholding obligations with respect to an award, those shares of common stock will again be available for delivery under the LTIP to the extent allowable by law.

Eligibility. Any individual who provides services to us, including non-employee directors and consultants, is eligible to participate in the LTIP (each, an “Eligible Person”). Each Eligible Person who is designated by the Compensation Committee to receive an award under the LTIP will be a “Participant.” An Eligible Person will be eligible to receive an award pursuant to the terms of the LTIP and subject to any limitations imposed by appropriate action of the Compensation Committee.

Administration. Our board of directors has appointed the Compensation Committee to administer the LTIP pursuant to its terms, except in the event our board of directors chooses to take action under the LTIP. Our Compensation Committee will, unless otherwise determined by the board of directors, be comprised of two or more individuals each of whom constitutes an “outside director” as defined in Section 162(m) of the Code and “nonemployee director” as defined in Rule 16b-3 under the Exchange Act. Unless otherwise limited, the Compensation Committee has broad discretion to administer the LTIP, including the power to determine to whom and when awards will be granted, to determine the amount of such awards (measured in cash, shares of common stock or as otherwise designated), to proscribe and interpret the terms and provisions of each award agreement, to accelerate the exercise terms of any award (provided that such acceleration does not cause an award intended to qualify as performance based compensation for purposes of Section 162(m) of the Code to fail to so qualify), to delegate duties under the LTIP and to execute all other responsibilities permitted or required under the LTIP.

Terms of Options. The Compensation Committee may grant options to Eligible Persons including (a) incentive stock options (only to our employees) that comply with Section 422 of the Code and (b) nonstatutory options. The exercise price for an option must not be less than the greater of (a) the par value per share of common stock or (b) the fair market value per share as of the date of grant. Options may be exercised as the Compensation Committee determines, but not later than 10 years from the date of grant. Any incentive stock option granted to an employee who possesses more than 10% of the total combined voting power of all classes of our shares within the meaning of Section 422(b)(6) of the Code must have an exercise price of at least 110% of the fair market value of the underlying shares at the time the option is granted and may not be exercised later than five years from the date of grant.

Terms of SARs. SARS may be awarded in connection with or separate from an option. An SAR is the right to receive an amount equal to the excess of the fair market value of one share of our common stock on the date of exercise over the grant price of the SAR. SARs awarded in connection with an option will entitle the holder, upon exercise, to surrender the related option or portion thereof relating to the number of shares for which the SAR is exercised, which option or portion thereof will then cease to be exercisable, in exchange for an amount calculated as described in the preceding sentence. Such SAR is exercisable or transferable only to the extent that the related option is exercisable or transferable. SARs granted independently of an option will be exercisable as the Compensation Committee determines. The term of an SAR will be for a period determined by the Compensation Committee but will not exceed ten years. SARs may be paid in cash, common stock or a combination of cash and stock, as provided for by the Compensation Committee in the award agreement.

Restricted Stock Awards. A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, restrictions on transferability, and any other restrictions imposed by the Compensation Committee in its discretion. Except as otherwise provided under the terms of the LTIP or an award agreement, the holder of a restricted stock award may have rights as a stockholder, including the right to vote or to receive dividends (subject to any mandatory reinvestment or other requirements imposed by the Compensation Committee). A restricted stock award that is subject to forfeiture restrictions may be forfeited and reacquired by us upon

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termination of employment or services. Common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, may be subject to the same restrictions and risk of forfeiture as the restricted stock with respect to which the distribution was made.

Restricted Stock Units. Restricted stock units are rights to receive common stock, cash or a combination of both at the end of a specified period. Restricted stock units may be subject to restrictions, including a risk of forfeiture, as specified in the award agreement. Restricted stock units may be satisfied by common stock, cash or any combination thereof, as determined by the Compensation Committee. Except as otherwise provided by the Compensation Committee in the award agreement or otherwise, restricted stock units subject to forfeiture restrictions will be forfeited upon termination of a participant’s employment or services prior to the end of the specified period. The Compensation Committee may, in its sole discretion, grant dividend equivalents with respect to restricted stock units.

Other Awards. Eligible Persons may be granted, subject to applicable legal limitations and the terms of the LTIP and its purposes, other awards related to common stock. Such awards may include, but are not limited to, common stock awarded as a bonus, dividend equivalents, convertible or exchangeable debt securities, other rights convertible or exchangeable into common stock, purchase rights for common stock, awards with value and payment contingent upon our performance or any other factors designated by the Compensation Committee, and awards valued by reference to the book value of common stock or the value of securities of or the performance of specified subsidiaries. The Compensation Committee will determine terms and conditions of all such awards. Cash awards may granted as an element of or a supplement to any awards permitted under the LTIP. Awards may also be granted in lieu of obligations to pay cash or deliver other property under the LTIP or under other plans or compensatory arrangements, subject to any applicable provision under Section 16 of the Exchange Act.

Performance Awards. The Compensation Committee may designate that certain awards granted under the LTIP constitute “performance” awards. A performance award is any award the grant, exercise or settlement of which is subject to one or more performance standards. These standards may include business criteria for us on a consolidated basis, such as total stockholders’ return and earnings per share, or for specific subsidiaries or business or geographical units.

Director Compensation

We did not award any compensation to our non-employee directors during fiscal year 2009. Going forward, the board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance, and that providing a total compensation package between the 50th percentile and 75th percentile of our peer group is necessary to accomplish that objective. Our board of directors also believes that the compensation package for our non-employee directors should require a significant portion of the total compensation package to be equity-based to align the interests of these directors with our stockholders.

After review with Longnecker & Associates of non-employee director compensation paid by our peer group, our board of directors approved the following compensation plan for non-employee directors for 2010 and later years:


	•	an annual cash retainer fee of $40,000, plus cash payments of $1,250 for each board of directors’ meeting attended and $1,000 for each committee meeting attended;

	•	an initial equity award of 4,500 shares of restricted stock; and

	•	an annual equity award of shares of our restricted stock having a value of $70,000 based on the average of the high and low market-quoted sales prices of our common stock on the grant date of the award.

Both the initial and annual grants of restricted stock will vest on the first anniversary of the grant date of the award.

In addition, the chairpersons of our Audit Committee, Compensation Committee and Nominating & Governance Committee will receive annual cash retainer fees of $10,000, $5,000 and $5,000, respectively.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Since January 1, 2007, there has not been, nor is there currently proposed, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation and Other Information,” and the transactions described or referred to below.

Corporate Reorganization

In connection with our corporate reorganization, we will engage in certain transactions with certain affiliates and our existing equity holders. Please see “Corporate Reorganization” for a description of these transactions.

Historical Transactions with Oasis Petroleum LLC

Since its inception, Oasis Petroleum LLC has issued additional membership interests as consideration for capital contributions received from its members, including EnCap, Oasis Petroleum Management LLC and other private investors. Capital contributions for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007 were $104.6 million, $80.5 million and $49.9 million, respectively. In addition, Oasis Petroleum LLC has paid the legal fees of EnCap and Oasis Petroleum Management LLC in connection with these transactions.

In connection with each of its capital contributions, EnCap receives a placement fee in an amount equal to 2% of its capital contributions. Such placement fees are remitted by us to EnCap or its designee. Placement fees for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007 were $1.6 million, $1.2 million and $1.0 million, respectively.

Service Agreements

Upon the completion of this offering, we will enter into service agreements with each of OAS Holdco and Oasis Petroleum Management LLC, pursuant to which we will agree to provide certain administrative services, including legal and accounting services. In return for such services, we will receive a monthly fee of $4,000, which we believe is a reasonable estimate of the costs and expenses we will incur by providing such services as well as reimbursement for any third party consultants engaged by us to provide such services.

Procedures for Approval of Related Person Transactions

A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “Related Person” means:


	•	any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

	•	any person who is known by us to be the beneficial owner of more than 5.0% of our common stock;

	•	any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5.0% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5.0% of our common stock; and

	•	any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest.

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CORPORATE REORGANIZATION

Oasis Petroleum Inc. is a Delaware corporation that was formed for the purpose of making this offering. Pursuant to the terms of a corporate reorganization that will be completed concurrently with the closing of this offering, Oasis Petroleum Inc. will acquire all of the outstanding membership interests in Oasis Petroleum LLC in exchange for shares of Oasis Petroleum Inc.’s common stock. Therefore, investors in this offering will only receive, and this prospectus only describes the offering of, shares of common stock of Oasis Petroleum Inc. Our business will continue to be conducted through Oasis Petroleum LLC, as a wholly owned subsidiary of Oasis Petroleum Inc. See “Description of Capital Stock” for additional information regarding the terms of our certificate of incorporation and bylaws as will be in effect upon the closing of this offering.

The reorganization will consist of a merger pursuant to which the outstanding membership interests in Oasis Petroleum LLC will be converted into membership interests in OAS Holdco. As a result of the merger, Oasis Petroleum LLC will become a wholly owned subsidiary of OAS Holdco. Pursuant to the contribution agreement by and among us, Oasis LLC, OAS Holdco, Merger LLC and an affiliate of EnCap, OAS Holdco will then contribute all of the membership interests in Oasis Petroleum LLC to Oasis Petroleum Inc. in exchange for 61,630,000 shares of common stock in Oasis Petroleum Inc. In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $9.1 million will be established for differences between the book and tax basis of our assets and liabilities and a corresponding expense will be recorded to net income from continuing operations.

Contemporaneously with Oasis Petroleum LLC becoming a wholly owned subsidiary of Oasis Petroleum Inc., the limited liability company agreement of Oasis Petroleum LLC will be amended and restated to terminate certain rights and obligations of its members.

We refer to (i) the reorganization pursuant to which the outstanding membership interests of Oasis Petroleum LLC will be converted into membership interests of OAS Holdco, (ii) the acquisition by Oasis Petroleum Inc. of all of the membership interests of Oasis Petroleum LLC in exchange for shares of Oasis Petroleum Inc.’s common stock, (iii) the effectiveness of the limited liability company agreement of OAS Holdco and (iv) the consummation of the other related transactions collectively as our “corporate reorganization.”

LLC Agreement of OAS Holdco

Members of Oasis Petroleum LLC, including Oasis Petroleum Management LLC, have entered into a limited liability company agreement, or LLC agreement, for OAS Holdco that will become effective upon the consummation of our corporate reorganization and this offering. Following the completion of this offering, but no earlier than 35 days from the pricing of this offering, OAS Holdco will make the following distributions to its members (based on the initial public offering price of $14.00 per share) as follows:


	•	a distribution to Oasis Petroleum Management LLC consisting of:


	•	2,500,000 shares of our common stock, which represents 5% of the outstanding shares of our common stock held by OAS Holdco immediately prior to this offering less the number of shares sold by OAS Holdco in this offering; and

	•	$7.7 million, which represents 5% of the net proceeds of this offering received by OAS Holdco as the selling stockholder;


	•	a distribution to certain private investors, including an officer of Simmons & Company International, and Oasis Petroleum Management LLC consisting of an aggregate of:


	•	345,704 shares of our common stock, which represents such investors’ proportionate interest (based on prior capital contributions other than capital contributions of Oasis Petroleum Management LLC) in the outstanding shares of our common stock held by OAS Holdco immediately prior to this offering less the number of shares sold by OAS Holdco in this offering; and

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	•	$1.1 million, which represents such investors’ proportionate interest (based on capital contributions other than capital contributions of Oasis Petroleum Management LLC) in the net proceeds of this offering received by OAS Holdco as the selling stockholder; and


	•	a distribution to all other members, including funds managed by EnCap and affiliates of certain of the underwriters, consisting of an aggregate of approximately $144.3 million, which represents the remaining net proceeds of this offering received by OAS Holdco as the selling stockholder.

Accordingly, although OAS Holdco will own 50,000,000 shares immediately after the completion of this offering, after giving effect to the foregoing distributions OAS Holdco will own 47,154,296 shares of our common stock, or approximately 51% of our outstanding shares of common stock based on the initial public offering price of $14.00 per share.

Subject to certain limitations, the foregoing distributions of shares of common stock by OAS Holdco are exempted from the 180-day lock up agreement between OAS Holdco and the underwriters entered into in connection with this offering and will require the filing of reports under Section 16 of the Exchange Act by OAS Holdco, certain other affiliates, and officers and directors of ours.

Contemporaneously with the completion of the distributions to certain private investors described above, such private investors will cease to be members in OAS Holdco and will become direct stockholders in us. In lieu of receiving cash distributions of the net proceeds of this offering received by OAS Holdco as the selling stockholder or the net proceeds of any future offering of our common stock by OAS Holdco, Oasis Petroleum Management LLC may elect to receive an equivalent distribution of shares of our common stock held by OAS Holdco based on the price per share received in such sale.

In addition to the distributions described above, the LLC agreement provides that OAS Holdco will make distributions to its members of the proceeds to its members from any future sales of our common stock by OAS Holdco based on the price per share received in such sale. The LLC Agreement also provides that OAS Holdco will make distributions to its members upon a sale of Oasis Petroleum Inc. based on the valuation in connection with such transaction. Unless otherwise determined by the board of managers of OAS Holdco, on the third anniversary of the expiration of the lock-up agreement between OAS Holdco and the underwriters entered into in connection with this offering, OAS Holdco LLC will automatically dissolve and distribute all remaining shares of our common stock to its members based on a valuation at such time. The number of shares received by Oasis Petroleum Management LLC will increase as the rate of return ultimately realized by the other members of OAS Holdco increases. For example, assuming a distribution of all of our remaining shares of common stock by OAS Holdco promptly after this offering at a valuation equal to the initial public offering price of $14.00 per share, Oasis Petroleum Management LLC would be entitled to receive 21% of the number of shares distributed by OAS Holdco, or approximately 11% of our total shares outstanding. For illustrative purposes and assuming a distribution of all of our remaining shares of common stock by OAS Holdco promptly after this offering at a hypothetical valuation of $20.00 per share, Oasis Petroleum Management LLC would be entitled to receive approximately 29% of the number of shares distributed by OAS Holdco, or approximately 15% of our total shares outstanding.

Oasis Petroleum Management LLC

Oasis Petroleum Management LLC was formed contemporaneously with Oasis Petroleum LLC to hold membership interests in Oasis Petroleum LLC on behalf of certain of our executive officers and other employees. Following the completion of the transactions described above, Oasis Petroleum Management LLC will own both a direct interest in our common stock and an indirect interest in us through OAS Holdco.

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth information with respect to the beneficial ownership of our common stock as of June 16, 2010 after giving effect to our corporate reorganization by:


	•	each of our named executive officers;

	•	each of our directors;

	•	all of our directors and executive officers as a group;

	•	the selling stockholder; and

	•	each stockholder known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock.

Except as otherwise indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more stockholders, as the case may be. The address for Michael McShane, the executive officers, OAS Holding Company LLC and Oasis Petroleum Management LLC is 1001 Fannin Street, Suite 202, Houston, TX 77002. The address for Douglas E. Swanson, Jr. and Robert L. Zorich is 1100 Louisiana Street, Suite 3150, Houston, TX 77002.


	Shares Beneficially Owned							Shares Beneficially Owned
Name of	Prior to the Offering					Shares Being		After the Offering
Beneficial Owner	Number		Percentage			Offered		Number		Percentage

Selling Stockholder and 5% Stockholder:
OAS Holding Company LLC(1)(2)		61,630,000		100	%		11,630,000		50,000,000		54.2	%
Directors and Executive Officers:
Thomas B. Nusz(3)(4)		—		—			—		2,593,156		2.8	%
Taylor L. Reid(3)(4)		—		—			—		2,590,156		2.8	%
Roy W. Mace(4)		—		—			—		11,550		*
Kent O. Beers(4)		—		—			—		13,350		*
Walter S. Smithwick(4)		—		—			—		12,450		*
Michael McShane(4)		—		—			—		40,200		*
Douglas E. Swanson, Jr.(1)(2)(4)		61,630,000		100	%		11,630,000		50,004,500		54.2	%
Robert L. Zorich(1)(2)(4)		61,630,000		100	%		11,630,000		50,004,500		54.2	%
All directors and executive officers as a group (11 persons)(1)(2)(4)		61,630,000		100	%		11,630,000		50,122,100		54.4	%


*		Less than 1%

(1)		Upon the completion of this offering, EnCap Energy Capital Fund VI, L.P. (“EnCap Fund VI”), EnCap VI-B Acquisitions, L.P. (“EnCap VI-B”) and EnCap Energy Capital Fund VII, L.P. (“EnCap Fund VII” and, together with EnCap Fund VI and EnCap VI-B, the “EnCap Funds”) collectively own an approximate 61% interest in OAS Holdco (based on the initial public offering price of $14.00 per share) and have the contractual right to nominate a majority of the members of the board of managers of OAS Holdco. The EnCap Funds may be deemed to beneficially own all of the reported securities held by OAS Holdco. The EnCap Funds are controlled indirectly by David B. Miller, Gary R. Petersen, D. Martin Phillips and Robert L. Zorich. Messrs. Miller, Petersen, Phillips and Zorich are members of RNBD GP LLC (“RNBD”) and any action taken by RNBD to dispose or acquire securities has to be unanimously approved by all four members. RNBD is the sole member of EnCap Investments GP, L.L.C. (“EnCap Investments GP”), which is the general partner of EnCap Investments L.P. (“EnCap Investments LP”), which is the general partner of EnCap Equity Fund VI GP, L.P. (“EnCap Fund VI GP”) and EnCap Equity Fund VII GP, L.P. (“EnCap

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		Fund VII GP”). EnCap Fund VI GP is the sole general partner of each of EnCap Fund VI and EnCap Fund VI-B, and EnCap Fund VII GP is the sole general partner of EnCap Fund VII. Messrs. Miller, Petersen, Phillips and Zorich, RNBD, EnCap Investments GP, EnCap Investments LP, EnCap Fund VI GP and EnCap Fund VII GP may be deemed to share dispositive power over the securities held by OAS Holdco; thus, they may also be deemed to be the beneficial owners of these securities. In addition, Messrs. Swanson, Zorich and Phillips represent three of the five members of OAS Holdco’s board of directors. Each of Messrs. Miller, Petersen, Phillips and Zorich, RNBD, EnCap Investments GP, EnCap Investments LP, EnCap Fund VI GP, EnCap Fund VII GP and the EnCap Funds disclaim beneficial ownership of the reported securities in excess of such entity’s or person’s respective pecuniary interest in the securities.

(2)		Includes 2,573,956 shares held by OAS Holdco that will be distributed to Oasis Petroleum Management LLC (based on the initial public offering price of $14.00 per share) within 60 days after the completion of this offering. Oasis Petroleum Management LLC is controlled by a board of managers consisting of Thomas B. Nusz and Taylor L. Reid, which exercises voting and dispositive power over all securities held by Oasis Petroleum Management LLC.

(3)		Prior to the offering excludes and after the offering includes 2,573,956 shares to be held by Oasis Petroleum Management LLC (based on the initial public offering price of $14.00 per share) within 60 days after the completion of this offering. Oasis Petroleum Management LLC is controlled by a board of managers consisting of Thomas B. Nusz and Taylor L. Reid, which exercises voting and dispositive power over all securities held by Oasis Petroleum Management LLC. Messrs. Nusz and Reid each disclaim beneficial ownership of the shares owned directly by Oasis Petroleum Management LLC except to the extent of their respective pecuniary interest.

(4)		Prior to the offering excludes and after the offering includes awards of restricted stock that will be granted to the directors and executive officers upon the closing of this offering as follows: Mr. Nusz — 19,200 shares; Mr. Reid — 16,200 shares; Mr. Mace — 11,550 shares; Mr. Beers — 13,350 shares; Mr. Smithwick — 12,450 shares; Mr. McShane — 40,200 shares; Mr. Swanson — 4,500 shares; and Mr. Zorich — 4,500 shares; all directors and executive officers as a group (11 persons) — 122,100 shares. See “Executive Compensation and Other Information — Compensation Discussion and Analysis — Elements of Our Compensation and Why We Pay Each Element — Long-Term Equity Based Incentives.”

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of Oasis Petroleum Inc. will consist of 300,000,000 shares of common stock, $0.01 par value per share, of which 92,215,295 shares will be issued and outstanding, and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

We will adopt an amended and restated certificate of incorporation and amended and restated bylaws concurrently with the completion of this offering. The following summary of the capital stock and certificate of incorporation and bylaws of Oasis Petroleum Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock, as such, are not entitled to vote on any amendment to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the General Corporation Law of the State of Delaware. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable. The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. In the event of any liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets that are remaining after payment or provision for payment of all of our debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.

Preferred Stock

Our certificate of incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law

Some provisions of Delaware law, and our certificate of incorporation and our bylaws described below, will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise; or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may

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otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

We will be subject to the provisions of Section 203 of the Delaware General Corporation Law, or DGCL, regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:


	•	the transaction is approved by the board of directors before the date the interested stockholder attained that status;

	•	upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

	•	on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Section 203 defines “business combination” to include the following:


	•	any merger or consolidation involving the corporation and the interested stockholder;

	•	any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder;

	•	subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder;

	•	any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or

	•	the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation.

In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

A Delaware corporation may “opt out” of Section 203 with an express provision in its original certificate of incorporation or an express provision in its certificate of incorporation or bylaws resulting from amendments approved by the holders of at least a majority of the corporation’s outstanding voting shares. We do not intend to “opt out” of the provisions of Section 203. The statute could prohibit or delay mergers or other takeover or change in control attempts and, accordingly, may discourage attempts to acquire us.

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Certificate of Incorporation and Bylaws

Among other things, upon the completion of this offering, our certificate of incorporation and bylaws will:


	•	establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

	•	provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

	•	provide that the authorized number of directors may be changed only by resolution of the board of directors;

	•	provide that all vacancies, including newly created directorships, may, except as otherwise required by law, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

	•	at any time after OAS Holdco and its affiliates no longer own more than 50% of the outstanding shares of our common stock,


	•	provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock (prior to such time, provide that such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

	•	provide that directors may be removed only for cause and only by the affirmative vote of holders of at least 80% of the voting power of our then outstanding common stock (prior to such time, provide that directors may be removed only for cause and only by the affirmative vote of the holders of at least a majority of our then outstanding common stock);

	•	provide our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock);

	•	provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, provide that a special meeting may also be called by stockholders holding a majority of the outstanding shares entitled to vote);


	•	provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. For more information on the classified board of directors, see “Management.” This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors;

	•	provide that we renounce any interest in the business opportunities of EnCap Investments, L.P. or any private fund that it manages or advises or any of its officers, directors, agents, stockholders, members, partners, affiliates and subsidiaries (other than Oasis directors that are presented business opportunities

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		in their capacity as an Oasis director) and that they have no obligation to offer us those opportunities; and


	•	provide that our bylaws can be amended or repealed at any regular or special meeting of stockholders or by the board of directors.

Limitation of Liability and Indemnification Matters

Our certificate of incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:


	•	for any breach of their duty of loyalty to us or our stockholders;

	•	for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

	•	for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

	•	for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our certificate of incorporation and bylaws also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our certificate of incorporation and bylaws also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Corporate Opportunity

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Listing

Our common stock has been approved for listing on the NYSE under the symbol “OAS.”

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect market prices prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon the closing of this offering, we will have outstanding an aggregate of 92,215,295 shares of common stock. Of these shares, all of the 42,000,000 shares of common stock to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 of the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, all of the shares of our common stock (excluding the shares to be sold in this offering) will be available for sale in the public market upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to extension) and when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We, all of our directors and officers, certain of our principal stockholders and the selling stockholder have agreed not to sell or otherwise transfer or dispose of any common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions and extensions. See “Underwriters” for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 as currently in effect, once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

Once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the New York Stock Exchange during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

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Rule 701

Employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written compensatory agreement in accordance with Rule 701 before the effective date of the registration statement are entitled to sell such shares 90 days after the effective date of the registration statement in reliance on Rule 144 without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issue Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register stock issuable under our Long-Term Incentive Plan. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Registration Rights

Prior to the consummation of this offering, we expect to enter into a registration rights agreement with the selling stockholder, which will require us to file and effect the registration of its shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering.

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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX
CONSIDERATIONS TO NON-U.S. HOLDERS

The following is a general discussion of the material U.S. federal income and estate tax consequences of the acquisition, ownership and disposition of our common stock to a non-U.S. holder. Except as specifically provided below (see “— Estate Tax”), for the purpose of this discussion, a non-U.S. holder is any beneficial owner of our common stock that is not for U.S. federal income tax purposes any of the following:


	•	an individual citizen or resident of the U.S.;

	•	a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in the U.S. or under the laws of the U.S. or any state or the District of Columbia;

	•	a partnership (or other entity treated as a partnership or other pass-through entity for U.S. federal income tax purposes);

	•	an estate whose income is subject to U.S. federal income tax regardless of its source; or

	•	a trust (x) whose administration is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust or (y) which has made a valid election to be treated as a U.S. person.

If a partnership (or an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership will generally depend on the status of the partner and upon the activities of the partnership. Accordingly, we urge partnerships that hold our common stock and partners in such partnerships to consult their tax advisors.

This discussion assumes that a non-U.S. holder will hold our common stock issued pursuant to the offering as a capital asset (generally, property held for investment). This discussion does not address all aspects of U.S. federal income taxation or any aspects of state, local or non-U.S. taxation, nor does it consider any U.S. federal income tax considerations that may be relevant to non-U.S. holders that may be subject to special treatment under U.S. federal income tax laws, including, without limitation, U.S. expatriates, life insurance companies, tax-exempt or governmental organizations, dealers in securities or currency, banks or other financial institutions, investors whose functional currency is other than the U.S. dollar, and investors that hold our common stock as part of a hedge, straddle or conversion transaction. Furthermore, the following discussion is based on current provisions of the Internal Revenue Code of 1986, as amended, and Treasury Regulations and administrative and judicial interpretations thereof, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect.

We urge each prospective investor to consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

Dividends

We have not paid any dividends on our common stock, and we do not plan to pay any dividends for the foreseeable future. However, if we do pay dividends on our common stock, those payments will constitute dividends for U.S. tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those dividends exceed our current and accumulated earnings and profits, the dividends will constitute a return of capital and will first reduce a holder’s adjusted tax basis in the common stock, but not below zero, and then will be treated as gain from the sale of the common stock (see “— Gain on Disposition of Common Stock).

Any dividend (out of earnings and profits) paid to a non-U.S. holder of our common stock generally will be subject to U.S. withholding tax either at a rate of 30% of the gross amount of the dividend or such lower rate as may be specified by an applicable tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide us with an IRS Form W-8BEN or other appropriate version of IRS Form W-8 certifying qualification for the reduced rate.

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Dividends received by a non-U.S. holder that are effectively connected with a U.S. trade or business conducted by the non-U.S. holder are exempt from such withholding tax. To obtain this exemption, the non-U.S. holder must provide us with an IRS Form W-8ECI properly certifying such exemption. Such effectively connected dividends, although not subject to withholding tax, will be subject to U.S. federal income tax on a net income basis at the same graduated rates generally applicable to U.S. persons, net of certain deductions and credits, subject to any applicable tax treaty providing otherwise. In addition to the income tax described above, dividends received by corporate non-U.S. holders that are effectively connected with a U.S. trade or business of the corporate non-U.S. holder may be subject to a branch profits tax at a rate of 30% or such lower rate as may be specified by an applicable tax treaty.

A non-U.S. holder of our common stock may obtain a refund of any excess amounts withheld if the non-U.S. holder is eligible for a reduced rate of United States withholding tax and an appropriate claim for refund is timely filed with the Internal Revenue Service or the IRS.

Gain on Disposition of Common Stock

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:


	•	the gain is effectively connected with a U.S. trade or business of the non-U.S. holder and, if required by an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by such non-U.S. holder;

	•	the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met; or

	•	we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes and the non-U.S. holder holds or has held, directly or indirectly, at any time within the shorter of the five-year period preceding the disposition or the non-U.S. holder’s holding period, more than 5% of our common stock. Generally, a corporation is a United States real property holding corporation if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we are, and will remain for the foreseeable future, a “U.S. real property holding corporation” for U.S. federal income tax purposes.

Unless an applicable tax treaty provides otherwise, gain described in the first bullet point above will be subject to U.S. federal income tax on net income basis at the same graduated rates generally applicable to U.S. persons. Corporate non-U.S. holders also may be subject to a branch profits tax equal to 30% (or such lower rate as may be specified by an applicable tax treaty) of its earnings and profits that are effectively connected with a U.S. trade or business.

Gain described in the second bullet point above (which may be offset by U.S. source capital losses, provided that the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses) will be subject to a flat 30% U.S. federal income tax (or such lower rate as may be specified by an applicable tax treaty).

Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules.

Backup Withholding and Information Reporting

Generally, we must report annually to the IRS the amount of dividends paid to each non-U.S. holder, the name and address of the recipient, and the amount, if any, of tax withheld with respect to those dividends. A similar report is sent to each non-U.S. holder. These information reporting requirements apply even if withholding was not required. Pursuant to tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient’s country of residence.

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Payments of dividends to a non-U.S. holder may be subject to backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, backup withholding may apply if either we or our paying agent has actual knowledge, or reason to know, that the beneficial owner is a U.S. person that is not an exempt recipient.

Payments of the proceeds from sale or other disposition by a non-U.S. holder of our common stock effected outside the U.S. by or through a foreign office of a broker generally will not be subject to information reporting or backup withholding. However, information reporting (but not backup withholding) will apply to those payments if the broker does not have documentary evidence that the holder is a non-U.S. holder, an exemption is not otherwise established, and the broker has certain relationships with the United States.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, information reporting and backup withholding may apply if the broker has actual knowledge, or reason to know, that the holder is a U.S. person that is not an exempt recipient.

Backup withholding is not an additional tax. Rather, the U.S. income tax liability of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Estate Tax

Our common stock owned or treated as owned by an individual who is not a citizen or resident of the U.S. (as specifically defined for U.S. federal estate tax purposes) at the time of death will be includible in the individual’s gross estate for U.S. federal estate tax purposes and may be subject to U.S. federal estate tax unless an applicable estate tax treaty provides otherwise.

Legislation Affecting Common Stock Held Through Foreign Accounts

On March 18, 2010, President Obama signed into law the Hiring Incentives to Restore Employment Act (the “HIRE Act”), which may result in materially different withholding and information reporting requirements than those described above, for payments made after December 31, 2012. The HIRE Act limits the ability of non-U.S. holders who hold our common stock through a foreign financial institution to claim relief from U.S. withholding tax in respect of dividends paid on our common stock unless the foreign financial institution agrees, among other things, to annually report certain information with respect to “United States accounts” maintained by such institution. The HIRE Act also limits the ability of certain non-financial foreign entities to claim relief from U.S. withholding tax in respect of dividends paid by us to such entities unless (1) those entities meet certain certification requirements; (2) the withholding agent does not know or have reason to know that any such information provided is incorrect and (3) the withholding agent reports the information provided to the IRS. The HIRE Act provisions will have a similar effect with respect to dispositions of our common stock after December 31, 2012. A non-U.S. holder generally would be permitted to claim a refund to the extent any tax withheld exceeded the holder’s actual tax liability. Non-U.S. holders are encouraged to consult with their tax advisers regarding the possible implication of the HIRE Act on their investment in respect of the common stock.

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UNDERWRITERS

Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom Morgan Stanley & Co. Incorporated and UBS Securities LLC are acting as representatives, have severally agreed to purchase, and we and the selling stockholder have agreed to sell to them, severally, the number of shares indicated below:


Name	Number of Shares

Morgan Stanley & Co. Incorporated		13,011,765
UBS Securities LLC		13,011,765
Simmons & Company International		6,884,706
J.P. Morgan Securities Inc.		1,704,706
Tudor, Pickering, Holt & Co. Securities, Inc.		1,704,706
Wells Fargo Securities, LLC		1,704,706
BNP Paribas Securities Corp.		378,824
Canaccord Genuity, Inc.		681,882
Johnson Rice & Company L.L.C.		681,882
Morgan Keegan & Company, Inc.		681,882
Raymond James & Associates, Inc.		681,882
RBC Capital Markets Corporation		681,882
Scotia Capital (USA) Inc.		189,412

Total		42,000,000

The underwriters and the representatives are collectively referred to as the “underwriters” and the “representatives,” respectively. The underwriters are offering the shares of common stock subject to their acceptance of the shares from us and the selling stockholder and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the shares of common stock offered by this prospectus are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the shares of common stock offered by this prospectus if any such shares are taken. However, the underwriters are not required to take or pay for the shares covered by the underwriters’ over-allotment option described below.

The per share price of any shares sold by the underwriters shall be the public offering price listed on the cover page of this prospectus, in United States dollars, less an amount not greater than the per share amount of the concession to dealers described below.

The underwriters initially propose to offer part of the shares of common stock directly to the public at the public offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $0.483 a share under the public offering price. After the initial offering of the shares of common stock, the offering price and other selling terms may from time to time be varied by the representatives.

The selling stockholder has granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to an aggregate of 6,300,000 additional shares of common stock at the public offering price listed on the cover page of this prospectus, less underwriting discounts and commissions. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with the offering of the shares of common stock offered by this prospectus. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase about the same percentage of the additional shares of common stock as the number listed next to the underwriter’s name in the preceding table bears to the total number of shares of common stock listed next to the names of all underwriters in the preceding table. If the underwriters’ option is exercised in full, the total price to the public for the additional shares will be approximately $88.2 million, the total underwriters’ discounts and

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commissions will be approximately $5.3 million, and the total proceeds to the selling stockholder will be approximately $82.9 million.

The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by us and by the selling stockholder. These amounts are shown assuming no exercise and full exercise of the underwriters’ option to purchase additional shares.


	Paid by Us				Paid by the Selling Stockholder
	No Exercise		Full Exercise		No Exercise		Full Exercise

Per Share	$	0.84	$	0.84	$	0.84	$	0.84
Total	$	25,510,800	$	25,510,800	$	9,769,200	$	15,061,200

We estimate that the expenses of the offering, not including underwriting discounts and commissions, will be approximately $4.0 million.

The underwriters have informed us that they do not intend sales to discretionary accounts to exceed 5% of the total number of shares of common stock offered by them.

Our common stock has been approved for listing on the NYSE under the symbol “OAS.”

We, all of our directors and officers, certain of our principal stockholders and the selling stockholder have agreed that, without the prior written consent of Morgan Stanley & Co. Incorporated and UBS Securities LLC and subject to certain exceptions, on behalf of the underwriters, we and they will not, during the period ending 180 days after the date of this prospectus:


	•	offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any shares of common stock beneficially owned or any securities so owned that are convertible into or exercisable or exchangeable for common stock;

	•	enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock; or

	•	file any registration statement with the SEC relating to the offering of any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock;

whether any such transaction described above is to be settled by delivery of common stock or such other securities, in cash or otherwise.

The restrictions described in the immediately preceding paragraph shall not apply to:


	•	the sale of shares to the underwriters pursuant to the underwriting agreement;

	•	the issuance by us of shares of common stock upon the exercise of an option or a warrant or the conversion of a security outstanding on the date of this prospectus of which the underwriters have been advised in writing;

	•	transactions relating to shares of common stock or other securities acquired in open market transactions after the completion of the offering of the shares; provided that no filing under Section 16(a) of the Exchange Act is required or will be voluntarily made in connection with subsequent sales of common stock or other securities acquired in such open market transactions;

	•	transfers of shares of common stock or any other security convertible into shares of our common stock as a bona fide gift; provided that each donee enters into a written agreement accepting the same lock-up restrictions as if it were the entity or individual originally subject to the lock-up agreement and no filing under Section 16(a) of the Exchange Act reporting a reduction in beneficial ownership of shares of common stock is required or will be voluntarily made in respect of the transfer or distribution during the 180-day restricted period;

	•	distributions of shares of common stock or any other security convertible into shares of our common stock to limited partners, members or stockholders of the selling stockholder or Oasis Petroleum Management LLC; provided that each distributee enters into a written agreement accepting the same lock-up restrictions as if it were the entity or individual originally subject to the lock-up agreement, and

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		no filing under Section 16(a) of the Exchange Act reporting a reduction in beneficial ownership of shares of common stock is required or will be voluntarily made in respect of the transfer or distribution during the 180-day restricted period. Notwithstanding the foregoing, OAS Holdco and Oasis Petroleum Management LLC may distribute shares of our common stock to specified members, which exempted persons may acquire in the aggregate less than 2% of our outstanding shares of our common stock or are persons who are executive officers or other persons already subject to lock-up agreements, provided that such distributions by OAS Holdco and Oasis Petroleum Management LLC occur at least 35 days after the pricing of this offering, and OAS Holdco or Oasis Petroleum Management LLC provides at least two business days’ prior written notice to the underwriters if OAS Holdco or Oasis Petroleum Management LLC is required to, or intends to voluntarily, file a report under Section 16 of the Exchange Act;


	•	the filing by us of a registration statement with the SEC on Form S-8 in respect of any shares issued under or the grant of any award pursuant to an employee benefit plan in effect on the date of this prospectus; or

	•	the establishment of a trading plan pursuant to Rule 10b5-1 under the Exchange Act for the transfer of shares of common stock; provided that such plan does not provide for the transfer of common stock during the 180-day restricted period and no public announcement or filing under the Exchange Act regarding the establishment of such plan is required of or voluntarily made by or on behalf of us.

In addition, the selling stockholder has agreed that, without the prior written consent of Morgan Stanley & Co. Incorporated and UBS Securities LLC, it will not, during the 180-day restricted period, make any demand for, or exercise any right with respect to, the registration of any shares of common stock or any security convertible into or exercisable or exchangeable for common stock.

The 180-day restricted period will be automatically extended if:


	•	during the last 17 days of the 180-day restricted period we issue an earnings release or material news or announce material event relating to us occurs; or

	•	prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period;

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

In order to facilitate the offering of the common stock, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common stock. Specifically, the underwriters may over-allot in connection with the offering, creating a short position in the common stock for their own account. In addition, to cover over-allotments or to stabilize the price of the common stock, the underwriters may bid for, and purchase, shares of common stock in the open market. Finally, the underwriting syndicate may reclaim selling concessions allowed to an underwriter or a dealer for distributing the common stock in the offering, if the syndicate repurchases previously distributed common stock in transactions to cover syndicate short positions, in stabilization transactions or otherwise. Any of these activities may stabilize or maintain the market price of the common stock above independent market levels. The underwriters are not required to engage in these activities, and may end any of these activities at any time.

We, the selling stockholder, certain of its affiliates and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act.

Directed Share Program Prospectus Disclosure

At our request, certain of the underwriters have reserved up to 5% of the common stock being offered by this prospectus (excluding any shares to be issued upon exercise of the over-allotment option) for sale at the initial public offering price to our directors, officers, employees, consultants, business associates, and related persons associated with us. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, through a directed share program. We do not know if these persons will choose to

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purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Any reserved shares which are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. Participants in the directed share program who purchase more than $100,000 of shares will be subject to a 180-day lock-up with respect to any shares sold to them pursuant to that program. This lock-up will have similar restrictions and an identical extension provision to the lock-up agreements described above. Any shares sold in the directed share program to our directors, executive officers or existing security holders will also be subject to the lock-up agreements described above. We have agreed to indemnify UBS Financial Services Inc. and the underwriters in connection with the directed share program, including for the failure of any participant to pay for its shares.

Pricing of the Offering

Prior to this offering, there has been no public market for our common stock. The initial public offering price is determined by negotiations between us, the selling stockholder and the representatives. Among the factors to be considered in determining the initial public offering price will be the information set forth in this prospectus, our history and prospects, the history of and prospects for our industry in general, our sales, earnings and certain other financial and operating information in recent periods, and the price-earnings ratios, price-sales ratios, market prices of securities, certain financial and operating information of companies engaged in activities similar to ours and other factors deemed relevant by the underwriters, the selling stockholder and us.

Relationships with Underwriters

From time to time in the ordinary course of business, certain of the underwriters and their respective affiliates have performed, and may in the future perform, various commercial banking, investment banking and other financial services for us for which they received, or will receive, customary fees and reimbursement of expenses. In particular, since September 2009, Simmons & Company International has provided financial advisory services for which it received financial consulting and advisory fees and reimbursement of expenses of $226,327. Further, an affiliate of BNP Paribas Securities Corp. is the administrative agent, sole lead arranger and sole bookrunner under our revolving credit facility. In addition, affiliates of UBS Securities LLC, J.P. Morgan Securities Inc., Wells Fargo Securities, LLC and BNP Paribas Securities Corp. serve as lenders under our revolving credit facility and will therefore receive their respective share of any repayment by us of amounts outstanding under our revolving credit facility from the net proceeds of this offering. However, each of these affiliates will receive less than 5% of the total net proceeds from this offering in connection with the repayment of this indebtedness. Affiliates of Wells Fargo Securities, LLC and BNP Paribas Securities Corp. and an officer of Simmons & Company International are members of the selling stockholder and accordingly will indirectly receive proceeds from the sale of shares by the selling stockholder as a result of a distribution of proceeds by the selling stockholder to its members. However, each of these affiliates will also receive less than 5% of the total net proceeds from this offering in connection with the distribution of proceeds from this offering by the selling stockholder.

The interests of Oasis Petroleum LLC acquired by affiliates of Wells Fargo Securities, LLC and BNP Paribas Securities Corp. and an officer of Simmons & Company International within 180 days prior to the required filing date of our registration statement (the initial filing date) are deemed underwriting compensation. Such underwriter or related person has agreed that any common or preferred stock, options, warrants and other equity securities of Oasis Petroleum Inc., including our debt securities convertible to or exchangeable for equity securities, that are unregistered and acquired by such underwriter or related person during the 180 days prior to the initial filing of our registration statement on Form S-1, or acquired after such required filing date of the registration statement and deemed to be underwriting compensation by FINRA, and any securities excluded from underwriting compensation pursuant to Section 5110(d)(5) of FINRA’s Corporate Financing Rule, shall not be sold during the offering, or sold, transferred, assigned, pledged or hypothecated, or be the subject of any hedging, short sale, derivative, put or call transaction that would result in the effective economic

134

disposition of the securities by any person for a period of 180 days immediately following the date of effectiveness or commencement of sales of this public offering, except as provided in Section 5110(g)(2) of FINRA’s Corporate Financing Rule.

Notice to Prospective Investors in the United Kingdom

Each underwriter has represented and agreed that:

(a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the UK Financial Services and Markets Act 2000, or FSMA) received by it in connection with the issue or sale of the shares of common stock which are the subject of the offering contemplated by this prospectus in circumstances in which Section 21(1) of the FSMA does not apply to us; and

(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares of common stock which are the subject of the offering contemplated by this prospectus in, from or otherwise involving the United Kingdom.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a relevant member state) an offer to the public of any shares of common stock which are the subject of the offering contemplated by this prospectus may not be made in that relevant member state, except that an offer to the public in that relevant member state of any shares of common stock may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that relevant member state:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43.0 million and (3) an annual net turnover of more than €50.0 million, as shown in its last annual or consolidated accounts;

(c) by the underwriters to fewer than 100 natural or legal persons (other than “qualified investors” as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(d) in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of shares of common stock shall result in a requirement for the publication by us or any underwriter of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state and the expression an “offer to the public” in relation to any shares of common stock in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and any shares of common stock to be offered so as to enable an investor to decide to purchase any shares of common stock, as the same may be varied in that relevant member state by any measure implementing the Prospectus Directive in that relevant member state.

Notice to Prospective Investors in Switzerland

This prospectus does not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations, or the CO, and the shares of common stock will not be listed on the SIX Swiss Exchange. Therefore, this prospectus may not comply with the disclosure standards of the CO and/or the listing rules (including any prospectus schemes) of the SIX Swiss Exchange. Accordingly, the shares of common stock may not be offered to the public in or from Switzerland, but only to a selected and limited circle of investors, which do not subscribe to the shares of common stock with a view to distribution.

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Notice to Prospective Investors in Australia

This prospectus is not a formal disclosure document and has not been, nor will be, lodged with the Australian Securities and Investments Commission. It does not purport to contain all information that an investor or their professional advisers would expect to find in a prospectus or other disclosure document (as defined in the Corporations Act 2001 (Australia)) for the purposes of Part 6D.2 of the Corporations Act 2001 (Australia) or in a product disclosure statement for the purposes of Part 7.9 of the Corporations Act 2001 (Australia), in either case, in relation to the securities.

The securities are not being offered in Australia to “retail clients” as defined in sections 761G and 761GA of the Corporations Act 2001 (Australia). This offering is being made in Australia solely to “wholesale clients” for the purposes of section 761G of the Corporations Act 2001 (Australia) and, as such, no prospectus, product disclosure statement or other disclosure document in relation to the securities has been, or will be, prepared.

This prospectus does not constitute an offer in Australia other than to wholesale clients. By submitting an application for our securities, you represent and warrant to us that you are a wholesale client for the purposes of section 761G of the Corporations Act 2001 (Australia). If any recipient of this prospectus is not a wholesale client, no offer of, or invitation to apply for, our securities shall be deemed to be made to such recipient and no applications for our securities will be accepted from such recipient. Any offer to a recipient in Australia, and any agreement arising from acceptance of such offer, is personal and may only be accepted by the recipient. In addition, by applying for our securities you undertake to us that, for a period of 12 months from the date of issue of the securities, you will not transfer any interest in the securities to any person in Australia other than to a wholesale client.

Notice to Prospective Investors in Hong Kong

Our securities may not be offered or sold in Hong Kong, by means of this prospectus or any document other than (i) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (ii) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong). No advertisement, invitation or document relating to our securities may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere) which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to the securities which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Japan

Our securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial Instruments and Exchange Law) and our securities will not be offered or sold, directly or indirectly, in Japan, or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan, or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

Notice to Prospective Investors in Singapore

This document has not been registered as a prospectus with the Monetary Authority of Singapore and in Singapore, the offer and sale of our securities is made pursuant to exemptions provided in sections 274 and 275 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA. Accordingly, this prospectus and

136

any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of our securities may not be circulated or distributed, nor may our securities be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor as defined in Section 4A of the SFA pursuant to Section 274 of the SFA, (ii) to a relevant person as defined in section 275(2) of the SFA pursuant to Section 275(1) of the SFA, or any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with the conditions (if any) set forth in the SFA. Moreover, this document is not a prospectus as defined in the SFA. Accordingly, statutory liability under the SFA in relation to the content of prospectuses would not apply. Prospective investors in Singapore should consider carefully whether an investment in our securities is suitable for them.

Where our securities are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

(a) by a corporation (which is not an accredited investor as defined in Section 4A of the SFA) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

(b) for a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor, shares of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable for six months after that corporation or that trust has acquired the shares under Section 275 of the SFA, except:

(1) to an institutional investor (for corporations under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or any person pursuant to an offer that is made on terms that such shares of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions, specified in Section 275 of the SFA;

(2) where no consideration is given for the transfer; or

(3) where the transfer is by operation of law.

In addition, investors in Singapore should note that the securities acquired by them are subject to resale and transfer restrictions specified under Section 276 of the SFA, and they, therefore, should seek their own legal advice before effecting any resale or transfer of their securities.

137

LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon for Oasis Petroleum Inc., by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Oasis Petroleum LLC as of December 31, 2009 and 2008 and for the period from February 26, 2007 (inception) to December 31, 2007 and for each of the two years ended December 31, 2009 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheet of Oasis Petroleum Inc. as of February 25, 2010 included in this prospectus has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The Statement of Revenues and Direct Operating Expenses of the Bill Barrett Corporation Acquisition Properties, the predecessor to Oasis Petroleum LLC, for the six month period ended June 30, 2007 and the Statement of Revenues and Direct Operating Expenses of the Kerogen Acquisition Properties for the year ended December 31, 2008 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves as of December 31, 2007, 2008 and 2009. The reserve estimates at December 31, 2007 and 2008 are based on reports prepared by W.D. Von Gonten & Co., independent reserve engineers. The reserve estimates at December 31, 2009 are based on a report prepared by DeGolyer and MacNaughton, independent reserve engineers. These estimates are included in this prospectus in reliance upon the authority of such firms as experts in these matters.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to us and the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of this contract, agreement or other document. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Section of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facility. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is http://www.sec.gov.

After we have completed this offering, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. We expect to have an operational website concurrently with the completion of this offering and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may read and copy any reports, statements or other information on file at the public reference rooms. You can also request copies of these documents, for a copying fee, by writing to the SEC, or you can review these documents on the SEC’s website, as described above. In addition, we will provide electronic or paper copies of our filings free of charge upon request.

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Report of Independent Registered Public Accounting Firm

To the Board of Managers of Oasis Petroleum LLC:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, members’ equity, and cash flows present fairly, in all material respects, the financial position of Oasis Petroleum LLC and its subsidiaries (the “Company”) at December 31, 2009 and 2008, and the results of their operations and their cash flows for the years ended December 31, 2009 and 2008, and for the period from February 26, 2007 (inception) to December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 4, 2010

F-2

Oasis Petroleum LLC

Consolidated Balance Sheet


	December 31,
	2009			2008
	(In thousands)

ASSETS
Current assets
Cash and cash equivalents	$	40,562		$	1,570
Accounts receivable — oil and gas revenues		9,142			794
Accounts receivable — joint interest partners		1,250			4,219
Inventory		1,258			1,569
Prepaid expenses		134			94
Advances to joint interest partners		4,605			2,274
Derivative instruments		219			3,284

Total current assets		57,170			13,804

Property, plant and equipment
Oil and gas properties (successful efforts method)		243,350			159,821
Other properties		866			747
Less: accumulated depreciation, depletion, amortization and impairment		(62,643	)		(46,348	)

Total property, plant and equipment, net		181,573			114,220

Derivative instruments		—			806
Deferred costs and other assets		810			238

Total assets	$	239,553		$	129,068


LIABILITIES AND MEMBERS’ EQUITY
Current liabilities
Accounts payable	$	1,577		$	2,573
Advances from joint interest partners		589			206
Production taxes and royalties payable		2,563			507
Accrued liabilities		18,038			12,716
Accrued interest payable		144			1
Derivative instruments		1,087			—

Total current liabilities		23,998			16,003

Long-term debt		35,000			26,000
Asset retirement obligations		6,511			4,458
Derivative instruments		2,085			—
Other liabilities		109			148

Total liabilities		67,703			46,609

Commitments and contingencies (see Note 10)
Members’ equity
Capital contributions		235,000			130,400
Accumulated loss		(63,150	)		(47,941	)

Total members’ equity		171,850			82,459

Total liabilities and members’ equity	$	239,553		$	129,068

The accompanying notes are an integral part of these consolidated financial statements.

F-3

Oasis Petroleum LLC

Consolidated Statement of Operations


							Period from
							February 26, 2007
	December 31,						(Inception) through
	2009			2008			December 31, 2007
	(In thousands)

Oil and gas revenues	$	37,755		$	34,736		$	13,791
Expenses
Lease operating expenses		8,691			7,073			2,946
Production taxes		3,810			3,001			1,211
Depreciation, depletion and amortization		16,670			8,686			4,185
Exploration expenses		1,019			3,222			1,164
Rig termination		3,000			—			—
Impairment of oil and gas properties		6,233			47,117			1,177
Gain on sale of properties		(1,455	)		—			—
General and administrative expenses		9,342			5,452			3,181

Total expenses		47,310			74,551			13,864

Operating loss		(9,555	)		(39,815	)		(73	)

Other income (expense)
Change in unrealized gain (loss) on derivative instruments		(7,043	)		14,769			(10,679	)
Realized gain (loss) on derivative instruments		2,296			(6,932	)		(1,062	)
Interest expense		(912	)		(2,404	)		(1,776	)
Other income (expense)		5			(9	)		40

Total other income (expense)		(5,654	)		5,424			(13,477	)

Net loss	$	(15,209	)	$	(34,391	)	$	(13,550	)

The accompanying notes are an integral part of these consolidated financial statements.

F-4

Oasis Petroleum LLC

Consolidated Statement of Cash Flows


							Period from
							February 26, 2007
	December 31,						(Inception) through
	2009			2008			December 31, 2007
	(In thousands)

Cash Flows from Operating Activities:
Net loss	$	(15,209	)	$	(34,391	)	$	(13,550	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		16,670			8,686			4,185
Exploration expenses		—			1,280			—
Impairment of oil and gas properties		6,233			47,117			1,177
Gain on sale of properties		(1,455	)		—			—
Derivative instruments		4,747			(7,837	)		11,741
Debt discount amortization		95			107			61
Working capital and other changes:
Change in accounts receivable		(6,409	)		(988	)		(4,008	)
Change in inventory		(218	)		(1,191	)		(505	)
Change in prepaid expenses		(40	)		(6	)		(88	)
Change in other assets		(667	)		—			—
Change in accounts payable and accrued liabilities		2,440			968			3,235
Change in other liabilities		(39	)		21			36

Net cash provided by operating activities		6,148			13,766			2,284

Cash flows from investing activities:
Capital expenditures		(47,396	)		(70,427	)		(8,876	)
Acquisition of oil and gas properties		(35,215	)		—			(82,010	)
Derivative settlements		2,296			(6,932	)		(1,062	)
Advances to joint interest partners		(2,331	)		(1,430	)		(40	)
Advances from joint interest partners		383			206			—
Proceeds from equipment and property sales		1,507			105			—

Net cash used in investing activities		(80,756	)		(78,478	)		(91,988	)

Cash flows from financing activities:
Proceeds from members’ contributions		104,600			80,500			49,900
Proceeds from issuance of debt		22,000			6,750			46,500
Reduction in debt		(13,000	)		(27,250	)		—
Debt issuance costs		—			—			(414	)

Net cash provided by financing activities		113,600			60,000			95,986

Increase (decrease) in cash and cash equivalents		38,992			(4,712	)		6,282
Cash and cash equivalents
Beginning of period		1,570			6,282			—

End of period	$	40,562		$	1,570		$	6,282

Supplemental cash flow Information:
Cash interest paid	$	674		$	2,485		$	1,526
Supplemental non-cash transactions:
Accrued capital expenditures	$	4,134		$	8,173		$	3,425
Asset retirement obligations		2,156			410			3,712

The accompanying notes are an integral part of these consolidated financial statements.

F-6

Oasis Petroleum LLC

Notes to Consolidated Financial Statements


1.	Organization and Operations of the Company

Organization

Oasis Petroleum LLC (“Oasis” or “Company”) was formed as a Delaware limited liability company on February 26, 2007 by certain members of the Company’s senior management team, through Oasis Petroleum Management LLC as described below, and private equity funds managed by EnCap Investments LLC (“EnCap”). EnCap, which was formed in 1988, provides private equity funding to independent oil and gas companies. As of December 31, 2009, EnCap was the majority holder and controlling member of the Company.

The Company entered into a limited liability company agreement dated March 5, 2007 (the “Oasis Agreement”) that provided for a maximum $100 million of capital contributions from EnCap and other members during a commitment period that extended from March 5, 2007 until March 10, 2010, unless extended by mutual agreement of EnCap and the Company (the “Commitment Period”). The Oasis Agreement was amended on November 1, 2007 to increase the maximum amount of capital contribution commitment from its members to $200 million. On December 1, 2009, the Oasis Agreement was further amended to extend the Commitment Period to December 31, 2011 and to increase the maximum amount of capital contribution commitment from its members to $275 million. The Company had $40 million of remaining capital commitment capacity under the Oasis Agreement, as amended, as of December 31, 2009.

Oasis Petroleum Management LLC (“OPM”), a Delaware limited liability company, was formed in February 2007 to allow Company employees to become indirect investors in the Company. OPM does not charge the Company management fees since all OPM investors are Oasis employees who receive compensation directly from the Company for their employment services. In April 2008, the Company formed Oasis Petroleum International LLC (“OPI”), a Delaware limited liability company, to conduct business development activities outside of the United States of America. OPI currently has no assets or business activities.

Nature of Business

The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. All of the Company’s assets, which consist of proved and unproved oil and natural gas properties located primarily in the Montana and North Dakota areas of the Williston Basin, are owned by Oasis Petroleum North America LLC (“OPNA”), a wholly owned subsidiary of the Company, which was formed on May 17, 2007 as a Delaware limited liability company.


2.	Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company include the accounts of Oasis and its wholly owned subsidiaries OPI and OPNA. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany transactions have been eliminated in consolidation.

Use of Estimates

Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement

F-7

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating cost and other factors. These revisions may be material and could materially affect future depletion, depreciation and amortization expense, dismantlement and abandonment costs, and impairment expense.

Cash and Cash Equivalents

All short-term investments purchased with an original maturity of three months or less are considered cash equivalents. The Company’s short-term investments are composed of overnight bank transfers of funds from bank accounts to an offshore United States Dollar denominated interest bearing account. Invested funds and earned interest amounts are returned to the Company’s accounts the next business day. Cash equivalents are stated at cost, which approximates market value.

Accounts Receivable

Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. No allowance for doubtful accounts was recorded for the years ended December 31, 2009 and 2008.

Inventory

Equipment and materials consist primarily of tubular goods and well equipment to be used in future drilling or repair operations and are stated at the lower of cost or market with cost determined on an average cost method. Crude oil inventories are valued at the lower of average cost or market value. Inventory consists of the following:


	December 31,
	2009		2008
	(In thousands)

Equipment and materials	$	588	$	1,117
Crude oil inventory		670		452

	$	1,258	$	1,569

F-8

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Joint Interest Partner Advances

The Company participates in the drilling of oil and gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.

Property, Plant and Equipment

Proved Oil and Gas Properties

The provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently. In December 2009, the Company sold its interests in non-core oil and natural gas producing properties located in the Barnett shale in Texas for an aggregate $1.5 million in cash. The Company recognized a gain of $1.4 million from the sale of these divested properties.

The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgement and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed in Note 4 — Fair Value Measurements. During the years ended December 31, 2009 and 2008, the Company recorded a $0.8 million and a $45.5 million non-cash

F-9

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

impairment charge, respectively, on its proved oil and natural gas properties. No impairment on proved oil and natural gas properties was recorded for the period ended December 31, 2007.

Unproved Oil and Gas Properties

Unproved properties consist of costs incurred to acquire unproved leases (“lease acquisition costs”). Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as Impairment of Oil and Gas Properties in the Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and records impairment expense for any decline in value. As a result of expiring unproved property leases, the Company recorded non-cash impairment charges of $5.4 million, $1.6 million and $1.2 million for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007, respectively.

Other Property and Equipment

Furniture, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses a five year period as the estimated life for these types of assets. The cost of assets disposed of and the associated accumulated depletion, depreciation and amortization are removed from the Company’s Consolidated Balance Sheet with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statement of Operations.

The following table sets forth the Company’s property, plant and equipment:


	December 31,
	2009			2008
	(In thousands)

Proved oil and gas properties	$	195,546		$	115,439
Less: Accumulated depreciation, depletion, amortization and impairment		(62,330	)		(46,188	)

Proved oil and gas properties, net		133,216			69,251
Unproved oil and gas properties		47,804			44,382
Other property and equipment		866			747
Less: Accumulated depreciation		(313	)		(160	)

Other property and equipment, net		553			587

Total property, plant and equipment, net	$	181,573		$	114,220

Exploration Expenses

Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.

F-10

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for the near future or the necessary approvals are actively being sought.

Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:


	December 31,
	2009			2008
	(In thousands)

Beginning of period	$	324		$	—
Exploratory well cost additions (pending determination of proved reserves)		72,972			38,666
Exploratory well cost reclassifications (successful determination of proved reserves)		(72,869	)		(37,633	)
Exploratory well dry hole costs (unsuccessful in adding proved reserves)		—			(709	)

End of period	$	427		$	324

For the period ended December 31, 2007, the Company’s drilling activity was conducted on proved undeveloped leasehold locations, and as such, there were no exploratory wells drilled in 2007.

As of December 31, 2009, the Company had no exploratory well costs that were capitalized for a period greater than one year.

Deferred Costs

The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in Deferred Costs and Other Assets on the Company’s Consolidated Balance Sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.

Asset Retirement Obligations

In accordance with the Financial Accounting Standard Board’s, or FASB’s, authoritative guidance on asset retirement obligations, or ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are depreciated using the unit-of-production method. The accretion expense is recorded as a component of Depreciation, Depletion and Amortization in the Company’s Consolidated Statement of Operations.

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 4 — Fair Value

F-11

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Revenue Recognition

Revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than 12 months) contracts at market based prices. The sales prices for oil and natural gas are adjusted for transportation and quality differentials. These differentials are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue differentials are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.

Production Taxes and Royalties Payable

The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.

Concentrations of Market Risk

The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint venture partners for their respective portions of operating expense and exploration and development costs. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. Trade receivables are generally not collateralized.

Concentrations of Credit Risk

The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company.

As of December 31, 2009, the Company’s customer base consists primarily of a major oil refining company, an oil and gas marketing firm, a large natural gas processing company and smaller oil and gas producers. The Company believes the credit quality of its customers is generally high. In the normal course of

F-12

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.

Risk Management

The Company utilizes derivative financial instruments (primarily swaps and zero-cost collars) to manage risks related to changes in oil prices. As of December 31, 2009, the Company utilized fixed-price swap agreements and zero-cost collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production. See Note 5 — Derivative Instruments.

The Company records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Realized gains and losses from the settlement of commodity derivative instruments and unrealized gains and losses from valuation changes in the remaining unsettled commodity derivative instruments are reported in the Other Income (Expense) section of the Company’s Consolidated Statement of Operations. Unrealized gains are included in current and noncurrent assets and unrealized losses are included in current and noncurrent liabilities on the Consolidated Balance Sheet, respectively.

Derivative financial instruments that hedge the price of oil are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with two counterparties, one of which is a lender under the Company’s revolving credit facility. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.

The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Company’s revolving credit facility. See Note 7 — Long-Term Debt. As of December 31, 2009, the revolving credit facility limited the total amount of current year production that may be hedged by the Company to 80% of projected production from proved developed producing reserves. As of December 31, 2009, the contractual commodity derivative volumes for 2010 and 2011 represent approximately 62% and 32%, respectively, of volumes from proved developed producing reserves, based on the Company’s reserve estimates at December 31, 2009.

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

F-13

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Income Taxes

Because the Company is electing to be treated as a partnership for tax purposes, the income or loss of the Company for federal and state income tax purposes is allocated to its members in accordance with the Oasis Agreement, as amended. Members are responsible for reporting their share of taxable income or loss on their separate income tax returns. Accordingly, no recognition has been given to federal or state income taxes in the accompanying consolidated financial statements.

The Company incurred a net loss for both book and income tax purposes for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007. As a result, each investor member was allocated net tax losses and the Company was not obligated to make cash tax distribution payments to its members.

Member Contributions and Distributions

The Oasis Agreement, as amended, defines the maximum amount of capital contribution commitment and the associated capital contribution percentage for each member. The Company’s Board of Managers determines whether capital contributions shall be made to the Company during the Commitment Period. Members are required to transfer funds for capital contributions, according to their respective percentages, upon receipt of a written notice from the Board of Managers. Capital contributions were $104.6 million, $80.5 million and $49.9 million for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007, respectively. In connection with each of its capital contributions, EnCap receives a placement fee in an amount equal to 2% of its capital contributions. Such placement fees are remitted by the Company to EnCap or its designee. Placement fees were $1.6 million, $1.2 million and $1.0 million for contributions made in 2009 and 2008 and the period ended December 31, 2007, respectively.

The Oasis Agreement, as amended, also defines the allocation of costs and revenues, which is proportionate to the members’ respective ownership percentage, as well as income tax allocations for each of the members’ accounts. The Company is responsible for providing income tax information related to each members’ account in order for such member to meet applicable state and federal tax reporting and filing requirements. Within 90 days after the end of each taxable year in which there is taxable income and sufficient working capital, as determined by the Board of Managers, the Company is obligated to make tax distributions to each member equal to tax obligations arising from the application of combined federal and applicable state and local income tax rates to such member’s share of taxable income for that tax year. Tax distributions are treated as capital advances and the cumulative amount of such advances will be deducted from future distribution events that are not tax distributions.

Distribution events, such as the sale or disposition of assets, are made according to the distribution percentages specified in the Oasis Agreement, as amended. There were no such distributions made in 2009 or 2008.

Fair Value of Financial and Non-Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and other payables approximate their respective fair market values due to their short maturities. The Company’s derivative instruments, long-term debt and asset retirement obligations are also recorded on the balance sheet at amounts which approximate fair market value. See Note 4 — Fair Value Measurements.

Recent Accounting Pronouncements

FASB Codification — In June 2009, the FASB issued authoritative guidance on the hierarchy of generally accepted accounting principles (“GAAP”), which established only two levels of GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (the “Codification”) became the single source of

F-14

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became non-authoritative. The Codification is effective for financial statements issued for interim or annual reporting periods ending after September 15, 2009. As the Codification was not intended to change or alter existing GAAP, it did not have any impact on the Company’s consolidated financial position, cash flows or results of operations.

Subsequent Events — In May 2009, the FASB issued authoritative guidance on subsequent events in order to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Particular importance has been placed on the period after the balance sheet date during which management should evaluate events or transactions that may occur, leading to recognition within the financial statements or disclosure in the financial statements. This guidance is effective for financial statements issued for interim or annual reporting periods ending after June 15, 2009. The adoption did not have a significant impact on the Company’s consolidated financial position, cash flows or results of operations. See Note 11 — Subsequent Events.

Fair Value Measurements — In September 2006, the FASB issued authoritative guidance on fair value measurements. This guidance defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. This guidance was effective for all recurring measures of financial assets and financial liabilities for fiscal years beginning after November 15, 2007, and was adopted by the Company on January 1, 2008. In February 2008, the FASB amended the authoritative guidance to delay the effective date of fair value accounting for nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis until fiscal years beginning after November 15, 2008. Beginning January 1, 2009, the Company implemented the guidance for nonfinancial assets and liabilities. The adoption of this guidance did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

In April 2009, the FASB amended existing authoritative guidance to provide additional application guidance and enhance disclosures regarding fair value measurements. This guidance intends to provide guidelines for making fair value measurements more consistent with other authoritative guidance and enhance consistency in financial reporting by increasing the frequency of fair value disclosures. This guidance is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The adoption of this guidance did not have a significant impact on the Company’s financial position, cash flows or results of operations. See Note 4 — Fair Value Measurements.

In January 2010, the FASB issued authoritative guidance to update disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies required to provide disclosures about recurring and nonrecurring fair value measurements, and are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for reporting periods within those years. The Company does not expect the adoption of this new guidance to have a significant impact on its financial position, cash flows or results of operations.

Oil and Gas Reporting Requirements — In December 2008, the Securities and Exchange Commission (“SEC”) released its final rule, “Modernization of Oil and Gas Reporting”, which adopts revisions to the SEC’s oil and gas reporting disclosure requirements. The disclosure requirements under this final rule require reporting of oil and gas reserves using the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months rather than year-end prices, and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are allowed, but not required, to disclose probable and possible reserves in SEC filings.

F-15

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

In addition, companies are required to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. In January 2010, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. The Company has presented and applied this new guidance for the year ended December 31, 2009 herein. See Note 13 — Supplemental Oil and Gas Reserve Information — Unaudited.

Disclosures about Derivative Instruments and Hedging Activities — In March 2008, the FASB issued authoritative guidance related to disclosures about derivative instruments and hedging activities. Disclosures previously required only for the annual financial statements are now required in interim financial statements. This guidance is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows and to improve the transparency of the location and amounts of derivative instruments in a company’s financial statements and how they are accounted for. This guidance was effective for the Company beginning January 1, 2009. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial position, results of operations or cash flows. See Note 5 — Derivative Instruments.

Business Combinations — In December 2007, the FASB revised the authoritative guidance for business combinations, extending its applicability to all transactions and other events in which one entity obtains control over one or more other businesses. The revised guidance broadens the fair value measurement and recognition of assets acquired, liabilities assumed and interests transferred as a result of business combinations and requires that acquisition-related costs incurred prior to the acquisition be expensed. The revised guidance also expands the definition of what qualifies as a business, and this expanded definition could include prospective oil and gas purchases. Additionally, this guidance expands the required disclosures to improve the financial statement users’ abilities to evaluate the nature and financial effects of business combinations. The guidance is effective for business combinations for which the acquisition date is on or after January 1, 2009. The Company has presented and applied this new guidance for all 2009 acquisitions that qualified as a business combination. See Note 3 — Acquisitions.

Non-Controlling Interests in Consolidated Financial Statements — In December 2007, the FASB issued authoritative guidance which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. This guidance is effective for fiscal years beginning after December 15, 2008. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial position, results of operations or cash flows.


3.	Acquisitions

Kerogen Acquisition — On June 15, 2009, the Company acquired interests in certain oil and gas properties primarily in the East Nesson area of the Williston Basin from Kerogen Resources, Inc. (the “Kerogen Acquisition Properties”) for $27.1 million (subject to closing adjustments). In addition to acquiring the interests in the East Nesson project area, the Company also acquired non-operated interests in the Sanish project area.

The acquisition qualifies as a business combination, and as such, the Company estimated the fair value of these properties as of the June 15, 2009 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future

F-16

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4 — Fair Value Measurements.

The Company estimates the fair value of the Kerogen Acquisition Properties to be approximately $27.1 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The acquisition related costs were insignificant.

The following table summarizes the consideration paid for the Kerogen Acquisition Properties and the fair value of the assets acquired and liabilities assumed as of June 15, 2009. The purchase price allocation is preliminary and subject to adjustment, as the final closing statement will be complete during first quarter of 2010.


Consideration given to Kerogen Resources, Inc. (in thousands):
Cash	$	27,087
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	25,178
Proved undeveloped properties		1,647
Unproved lease acquisition costs		360
Seismic costs		667
Asset retirement obligations		(765	)

Total identifiable net assets	$	27,087

Summarized below are the consolidated results of operations for the years ended December 31, 2009 and 2008, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Kerogen Acquisition Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.


	Year Ended December 31,
	2009						2008
	Actual			Pro Forma			Actual			Pro Forma
	(In thousands)
	Unaudited

Kerogen Acquisition Properties:
Revenues	$	37,755		$	41,999		$	34,736		$	51,314
Net Loss	$	(15,209	)	$	(15,461	)	$	(34,391	)	$	(25,858	)

Fidelity Acquisition — On September 30, 2009, the Company acquired additional interests in the East Nesson project area of the Williston Basin from Fidelity Exploration and Production Company (the “Fidelity Acquisition Properties”) for $10.7 million (subject to closing adjustments).

The acquisition qualifies as a business combination, and as such, the Company estimated the fair value of these properties as of the September 30, 2009 acquisition date. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs,

F-17

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4 — Fair Value Measurements.

The Company estimates the fair value of the Fidelity Acquisition Properties to be approximately $10.7 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The acquisition related costs were insignificant.

The following table summarizes the consideration paid for the Fidelity Acquisition Properties and the fair value of the assets acquired and liabilities assumed as of September 30, 2009. The purchase price allocation is preliminary and subject to adjustment, as the final closing statement will be complete during first quarter of 2010.


Consideration given to Fidelity Exploration and Production Company (in thousands):
Cash	$	10,681
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	4,668
Proved undeveloped properties		2,415
Unproved lease acquisition costs		3,450
Seismic costs		667
Asset retirement obligations		(519	)

Total identifiable net assets	$	10,681

Summarized below are the consolidated results of operations for the years ended December 31, 2009 and 2008, on an unaudited pro forma basis as if the acquisition had occurred on January 1 of each of the periods presented. The pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Fidelity Acquisition Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.


	Year Ended December 31,
	2009						2008
	Actual			Pro Forma			Actual			Pro Forma
	(In thousands)
	Unaudited

Fidelity Acquisition Properties:
Revenues	$	37,755		$	40,934		$	34,736		$	38,438
Net Loss	$	(15,209	)	$	(15,872	)	$	(34,391	)	$	(33,065	)


4.	Fair Value Measurements

The Company adopted the FASB’s authoritative guidance on fair value measurements effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. Beginning January 1, 2009, the Company also applied this guidance to non-financial assets and liabilities. The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

F-18

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards and options.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:


	At fair value as of December 31, 2009
	Level 1		Level 2		Level 3			Total
			(In thousands)

Assets (Liabilities):
Commodity Derivative Instruments (see Note 5)	$	—	$	—	$	(2,953	)	$	(2,953	)

Total Derivative Instruments	$	—	$	—	$	(2,953	)	$	(2,953	)

F-19

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)


	At fair value as of December 31, 2008
	Level 1		Level 2		Level 3		Total
			(In thousands)

Assets (Liabilities):
Commodity Derivative Instruments (see Note 5)	$	—	$	—	$	4,090	$	4,090

Total Derivative Instruments	$	—	$	—	$	4,090	$	4,090

The Level 3 instruments presented in the tables above consist of oil swaps and collars. The Company utilizes the mark-to-market valuation reports provided by its counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculated the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s current cost of prime based borrowings (prime rate and associated margin effect). Based on these calculations, the Company recorded a downward adjustment to the fair value of its derivative instruments in the amount of $0.08 million at December 31, 2009.

The following table presents a reconciliation of the changes in fair value of the derivative instruments classified as Level 3 in the fair value hierarchy for the years presented.


	2009			2008
	(In thousands)

Balance as of January 1	$	4,090		$	(10,679	)
Total gains or (losses) (realized or unrealized):
Included in earnings		(4,747	)		7,837
Included in other comprehensive income		—			—
Purchases, issuances and settlements		(2,296	)		6,932
Transfers in and out of level 3		—			—

Balance as of December 31	$	(2,953	)	$	4,090

Change in unrealized gains (losses) included in earnings relating to derivatives still held at December 31	$	(7,043	)	$	14,769

At December 31, 2009, the Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The carrying amount of long-term debt reported in the Consolidated Balance Sheet at December 31, 2009 is $35.0 million, which approximates fair value due to the short term maturity of the debt obligations (see Note 7 — Long-Term Debt). The carrying amount of the Company’s ARO in the Consolidated Balance Sheet at December 31, 2009 is $6.5 million, which also approximates fair value as the Company determines the ARO by calculating the present value of estimated cash flows related to the liability based on the calculation of the estimated value (see Note 2 — Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Therefore, the Company’s proved oil and natural gas properties are measured at fair value on a non-recurring basis. During the years ended December 31, 2009 and 2008, the Company recorded a $0.8 million and a $45.5 million non-cash impairment charge, respectively, on its proved oil and natural gas properties, as further discussed in Note 2 — Summary of Significant Accounting Policies. The 2009 impairment charge related to certain dry holes, which had a fair value of zero. The oil and natural gas properties related to the 2008

F-20

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

impairment charge had a fair value of $22.3 million and were evaluated for impairment primarily due to lower crude oil prices at December 31, 2008.


5.	Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2009, the Company utilized fixed-price swap agreements and zero-cost collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production.

All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their fair value (see Note 4 — Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value, both realized and unrealized, are recognized in the Other Income (Expense) section of the Consolidated Statement of Operations as a gain or loss on mark-to-market derivative contracts. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.

As of December 31, 2009, the Company had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges:


		Total Notional		Average		Average
Settlement	Derivative	Amount of Oil		Floor		Ceiling				Fair Market
Period	Instrument	(Barrels)		Prices		Prices		Fixed Price		Value
										(In thousands)

2010	NYMEX Swap		11,163					$	72.25	$	(26	)
2010	NYMEX Collar		401,814	$	67.48	$	90.19				(841	)
2011	NYMEX Collar		186,764	$	61.49	$	82.23				(1,912	)
2012	NYMEX Collar		13,618	$	60.00	$	80.25				(174	)

										$	(2,953	)

The following table summarizes the location and fair value of all outstanding commodity derivative contracts recorded in the balance sheet that do not qualify for hedge accounting for the periods presented:


Fair Value of Derivative Instrument Assets (Liabilities)
		Fair Value
		December 31,
Instrument Type	Balance Sheet Location	2009			2008
		(In thousands)

Crude oil swap	Derivative Instruments — current assets	$	—		$	2,551
Crude oil collar	Derivative Instruments — current assets		219			733
Crude oil swap	Derivative Instruments — non-current asset		—			136
Crude oil collar	Derivative Instruments — non-current asset		—			670
Crude oil swap	Derivative Instruments — current liabilities		(26	)		—
Crude oil collar	Derivative Instruments — current liabilities		(1,061	)		—
Crude oil collar	Derivative Instruments — non-current liabilities		(2,085	)		—

	Total Derivative Instruments	$	(2,953	)	$	4,090

F-21

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes the location and amounts of realized and unrealized gains and losses from the Company’s commodity derivative contracts that do not qualify for hedge accounting for the periods presented:


		December 31,
	Income Statement Location	2009			2008
		(In thousands)

Derivative Contracts	Change in Unrealized Gain (Loss) on Derivative Instruments	$	(7,043	)	$	14,769
Derivative Contracts	Realized Gain (Loss) on Derivative Instruments		2,296			(6,932	)

	Total Commodity Derivative Gain (Loss)	$	(4,747	)	$	7,837


6.	Accrued Liabilities

The Company’s accrued liabilities consist of the following:


	December 31,
	2009		2008
	(In thousands)

Accrued capital costs	$	14,754	$	10,620
Accrued lease operating expense		1,560		631
Accrued general and administrative expense		1,056		599
Other		668		866

Total	$	18,038	$	12,716

In addition, the Company had production taxes payable of $1.2 million and $0.1 million for the years ended December 31, 2009 and 2008, respectively, included in Production Taxes and Royalties Payable on the Consolidated Balance Sheet.


7.	Long-Term Debt

The Company, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007, which was subsequently amended on June 10, 2008, May 13, 2009 and June 23, 2009 (as amended, the “Credit Facility”). Under the Credit Facility, BNP Paribas, as administrative agent, and JPMorgan Chase Bank, as syndication agent, (collectively the “Lenders”) provide the Company with a senior secured revolving line of credit that is collateralized by all of the Company’s oil and natural gas properties. Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports.

The Credit Facility provides for periodic scheduled redeterminations of the collateral value of the Company’s oil and natural gas properties to determine the allowable borrowing base. Upon completing its review of the Company’s interim oil and gas reserves report as of September 1, 2009, the Lenders provided a letter notification that a $45 million maximum borrowing base would become effective upon payment of the associated banking fees, which were paid on October 19, 2009.

Borrowings under the Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London Interbank Offered Rate (“LIBOR”) loan or a bank prime interest

F-22

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

rate loan (defined in the Credit Facility as an Alternate Based Rate or “ABR” loan). The LIBOR and ABR loans bear their respective interest rates plus the applicable margin indicated in the following table:


	Applicable Margin			Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base	for LIBOR Loans			for ABR Loans

Less than .50 to 1		2.25	%		0.75	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.50	%		1.00	%
Greater than or equal to .75 to 1 but less than .85 to 1		2.75	%		1.25	%
Greater than .85 to 1 but less than or equal 1		3.00	%		1.50	%

An ABR loan does not have a set maturity date and may be repaid at any time upon the Company providing advance notification to the Lenders. Interest is paid quarterly for ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum loan term is six months for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms greater than three months in duration. At the end of a LIBOR loan term, the Credit Facility allows the Company to elect to continue a LIBOR loan with the same or a differing loan term or convert the borrowing to an ABR loan. Because the Credit Facility has a final maturity date of June 22, 2011, outstanding borrowings are classified as long-term debt in the Company’s Consolidated Balance Sheet at December 31, 2009.

On a quarterly basis, the Company also pays a 0.50% commitment fee on the daily amount of borrowing base capacity not utilized during the quarter and fees calculated on the daily amount of letter of credit balances outstanding during the quarter.

For LIBOR loans, interest is payable at the maturity of the loan term. For ABR loans, interest is payable quarterly until such time the ABR loan balance is repaid or converted to a LIBOR loan.

The Credit Facility contains covenants that include, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;

	•	a prohibition against making investments, loans and advances, subject to permitted exceptions;

	•	restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;

	•	restrictions on merging and selling assets outside the ordinary course of business;

	•	restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;

	•	a provision limiting oil and natural gas hedging transactions to a volume not exceeding 80 percent (other than puts or floors not exceeding 100 percent) of anticipated production from proved developed producing reserves;

	•	a requirement that the Company not allow a ratio of Total Debt (as defined in the Credit Facility) to consolidated EBITDAX (as defined in the Credit Facility) to be greater than 4.5 to 1.0 for any period to and including December 31, 2009 and to be greater than 4.0 to 1.0 for any period thereafter; and

	•	a requirement that the Company maintain a Current Ratio of consolidated current assets (with exclusions as described in the Credit Facility) to consolidated current liabilities (with exclusions as described in the Credit Facility) of not less than 1.0 to 1.0.

F-23

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

The Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

As of December 31, 2009, borrowings under the Credit Facility totaled $35.0 million and outstanding letters of credit issued under the Credit Facility totaled $0.2 million, resulting in unused borrowing base capacity of $9.8 million. The weighted average interest rate incurred on the outstanding Credit Facility borrowings during 2009 was 3.5%.


8.	Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the years ended December 31, 2009 and 2008:


	December 31,
	2009			2008
	(In thousands)

Asset retirement obligation — beginning of period	$	4,458		$	3,833
Liabilities incurred through acquisitions		1,285			—
Liabilities incurred during period		859			410
Liabilities settled during period		(395	)		(83	)
Accretion expense during period		362			298
Revisions to estimates		(58	)		—

Asset retirement obligation — end of period	$	6,511		$	4,458


9.	Significant Concentrations

Purchasers that accounted for more than 10% of the Company’s total sales for the periods presented are as follows:

Period from

Year Ended

February 26, 2007

December 31,

(Inception) through

2009

2008

December 31, 2007

Tesoro Refining and Marketing Company

32%

57%

79%

Texon L.P.(1)

30%

14%

N/A


(1)		Not applicable for the period from February 26, 2007 (Inception) through December 31, 2007 as the sales to Texon L.P. did not account for more than 10% of the Company’s total sales.

No other purchasers accounted for more than 10% of the Company’s total oil and natural gas sales for the years ended December 31, 2009 and 2008 and the period ended December 31, 2007. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing regions.

Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. Zenergy Operating, Bristol Exploration LP and Abraxas Petroleum Corporation accounted for approximately 27%, 19% and 13%, respectively, of the Company’s JIB receivables balance at December 31, 2009. Hess Corporation and Windsor Bakken LLC accounted for approximately 41% and 13%, respectively, of the Company’s JIB receivables balance at December 31, 2008. No other individual account balances accounted for more than 10% of the Company’s total JIB receivables at December 31, 2009 and 2008.

F-24

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.


10.	Commitments and Contingencies

Lease Obligations — The Company has operating leases for office space. The Company incurred lease rental expenses of $332,104 and $278,149 for the years ended December 31, 2009 and 2008, respectively, and $119,100 for the period ended December 31, 2007. Future minimum annual rental commitments under noncancelable leases as of and subsequent to December 31, 2009 are as follows:


	(In thousands)

2010	$	451
2011		387
2012		131
2013		—
Thereafter		—

	$	969

Drilling Contracts — During 2008, the Company entered into drilling rig contracts with two drilling contractors. In the fourth quarter of 2008, the Company reduced its planned 2009 capital expenditure program and entered into discussions regarding early termination of these contracts. In the first quarter of 2009, the Company paid a total of $3.0 million in rig termination fees in connection with the rig termination of the Company’s remaining commitment under one drilling rig contract and the extension of the other drilling rig contract until June 2010. The Company agreed to retain an obligation to pay for 60 remaining shortfall days if the drilling rig was not used during the remaining term of the contract.

In November 2009, the Company entered into a new six-month term drilling rig contract, which replaced the contract the Company had previously extended. In the event of an early termination under this new drilling contract, the Company is obligated to pay a daily shortfall rate of $9,000 per day for the days remaining between the date of termination and May 15, 2010, the end of the primary contract term.

Litigation — There are no claims, title matters or other legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under oil and gas operating agreements and other contractual disputes that are pending or threatened against the Company at this time. The Company purchases and maintains general liability and other insurance to cover such potential liabilities.


11.	Subsequent Events

The Company has evaluated the period after the balance sheet date up through March 4, 2010, the date the consolidated financial statements were issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

New Drilling Rig Contract — On January 27, 2010, the Company entered into a new drilling rig contract. In the event of early contract termination under this new contract, the Company is obligated to pay a daily shortfall rate of $8,000 per day for the days remaining between the date of termination and June 15, 2010, the end of the primary contract term. On February 22, 2010, the Company extended the term of this contract by one month to July 15, 2010. All other rates, terms and conditions of the rig contract remained unchanged.

Amended and Restated Credit Facility — On February 26, 2010, the Company entered into an agreement that amended and restated the existing Credit Facility (the “Amended Credit Facility”). The Amended Credit

F-25

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Facility increased the initial borrowing base to a maximum of $85 million, defined a future borrowing base of $70 million (the “Conforming Borrowing Base”) and extended the maturity date of the Amended Credit Facility to February 26, 2014.

If the Company does not consummate an initial public stock offering before October 1, 2010, then the Borrowing Base shall equal the Conforming Borrowing Base on that date. The Conforming Borrowing Base is used as the denominator when calculating the utilization percentage of the Amended Credit Facility (the dollar amount of outstanding borrowings divided by the Conforming Borrowing Base).

Borrowings under the Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a bank prime ABR loan. The LIBOR and ABR loans bear their respective interest rates plus the applicable margin as indicated in the following table:


	Applicable Margin			Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base	for LIBOR Loans			for ABR Loans

Less than .50 to 1		2.25	%		0.75	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.50			1.00
Greater than or equal to .75 to 1 but less than .85 to 1		2.75			1.25
Greater than .85 to 1 but less than or equal 1		3.00			1.50
Greater than 1 but less than 1.125		3.50			2.00
Greater than 1.125		4.00			2.50

At the time in which the Conforming Borrowing Base ceases to be in effect, the highest level for the Ratio of Total Outstanding Borrowings to Borrowing Base will be the “Greater than .85 to 1 but less than or equal to 1” level in the above table.

The Amended Credit Facility agreement retained the same quarterly fee payments for commitment and letter of credit fees and retained the same covenants as previously described for the Credit Facility (see Note 7 — Long-Term Debt).


12.	Supplemental Oil and Gas Disclosures

The supplemental data presented herein reflects information for all of the Company’s oil and natural gas producing activities.

Capitalized Costs

The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2009 and 2008:


	December 31,
	2009			2008
	(In thousands)

Proved properties	$	195,546		$	115,439
Less: Accumulated depreciation, depletion, amortization and impairment		(62,330	)		(46,188	)

Proved properties, net		133,216			69,251
Unproved properties		47,804			44,382

Total oil and gas properties, net	$	181,020		$	113,633

Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $5.4 million and $4.0 million at December 31, 2009 and 2008, respectively.

F-26

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2009 and 2008 and for the period from February 26, 2007 (inception) through December 31, 2007:


	Year Ended December 31,				Period from February 26, 2007 (Inception) through
	2009		2008		December 31, 2007
	(In thousands)

Acquisition costs:
Proved properties	$	35,134	$	36,969	$	12,862
Unproved properties		13,917		—		69,680
Exploration costs		1,019		3,222		1,164
Development costs		38,526		39,025		11,403
Asset retirement costs		1,314		—		3,712

Total costs incurred	$	89,910	$	79,216	$	98,821

Results of Operations for Oil and Natural Gas Producing Activities

Results of operations for oil and natural gas producing activities, which excludes straight-line depreciation, general and administrative expense and interest expense, are presented below.


							Period from
							February 26, 2007
	December 31,						(Inception) through
	2009			2008			December 31, 2007
	(In thousands)

Revenues	$	37,755		$	34,736		$	13,791

Production costs		12,501			10,074			4,157
Depreciation, depletion and amortization		16,592			8,581			4,153
Exploration costs		1,019			3,222			1,164
Rig termination		3,000			—			—
Impairment of oil and gas properties		6,233			47,117			1,177
Gain on sale of properties		(1,455	)		—			—

Results of operations for oil and gas producing activities	$	(135	)	$	(34,258	)	$	3,140


13.	Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates at December 31, 2009 presented in the table below are based on a report prepared by DeGolyer and MacNaughton, independent reserve engineers, in accordance with the FASB’s new authoritative guidance on oil and gas reserve estimation and disclosures. The reserve estimates at December 31, 2008 and 2007 presented in the table below are based on reports prepared by W.D. Von Gonten & Co. using the FASB rules in effect at that time. At December 31, 2009, all of the Company’s oil and natural gas producing activities were conducted within the continental United States.

F-27

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited

The following table sets forth the Company’s net proved, proved developed and proved undeveloped reserves at December 31, 2009, 2008 and 2007:


	Oil			Gas
	(MBbl)			(MMcf)			MBoe

2007 (1)
Proved reserves
Beginning balance		—			—			—
Revisions of previous estimates		(58	)		137			(35	)
Extensions, discoveries and other additions		279			42			286
Sales of reserves in place		—			—			—
Purchases of reserves in place		3,982			1,133			4,171
Production		(159	)		(73	)		(171	)

Net proved reserves at December 31, 2007		4,044			1,239			4,251

Proved developed reserves, December 31, 2007		3,266			1,083			3,447

Proved undeveloped reserves, December 31, 2007		778			156			804

2008
Proved reserves
Beginning balance		4,044			1,239			4,251
Revisions of previous estimates		(1,604	)		(479	)		(1,684	)
Extensions, discoveries and other additions		132			34			137
Sales of reserves in place		—			—			—
Purchases of reserves in place		—			—			—
Production		(379	)		(123	)		(400	)

Net proved reserves at December 31, 2008		2,193			671			2,304

Proved developed reserves, December 31, 2008		2,193			671			2,304

Proved undeveloped reserves, December 31, 2008		—			—			—

2009
Proved reserves
Beginning balance		2,193			671			2,304
Revisions of previous estimates		781			(84	)		767
Extensions, discoveries and other additions		8,381			3,414			8,950
Sales of reserves in place		(2	)		(16	)		(5	)
Purchases of reserves in place		1,726			1,611			1,995
Production		(658	)		(326	)		(712	)

Net proved reserves at December 31, 2009		12,421			5,270			13,299

Proved developed reserves, December 31, 2009		5,231			2,293			5,613

Proved undeveloped reserves, December 31, 2009		7,190			2,977			7,686

F-29

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)


(1)		No beginning balance as the Company purchased the reserves from Bill Barrett Corporation in July 2007. Amounts represent changes from the date of acquisition to December 31, 2007.

Purchases of Reserves in Place

Of the total 1,995 MBoe of reserves purchased in 2009, 1,511 MBoe were from the Kerogen Acquisition Properties and 484 MBoe were from the Fidelity Acquisition Properties. The Company did not purchase reserves in place in 2008. In 2007, all of the 4,171 MBoe of total reserves purchased were from the properties acquired from Bill Barrett Corporation located in the Williston Basin.

Extensions, Discoveries and Other Additions

In 2009, the Company had a total of 8,950 MBoe of additions. An estimated 1,508 MBoe of extensions and discoveries were associated with new wells, which were producing at December 31, 2009, with approximately 95% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 7,442 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2009 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

In 2008, the Company had a total of 137 MBoe of additions. An estimated 127 MBoe resulted from the Company’s 2008 Bakken drilling program in the East Nesson project area.

In 2007, the Company had a total of 286 MBoe of additions. Approximately 81 MBoe resulted from non-operated wells in the Company’s Bakken drilling program in the West Williston project area. The Company also added an estimated 205 MBoe of proved undeveloped reserves in the conventional Madison formation.

Sales of Reserves in Place

In 2009, the Company sold a portion its interests in non-core oil and gas producing properties located in the Barnett shale in Texas, which had minimal impact on the Company’s proved reserves. The Company had no divestitures for the year ended December 31, 2008 and the period ended December 31, 2007.

Revisions of Previous Estimates

In 2009, the Company had net positive revisions of 767 MBoe, primarily due to the increase in oil prices. The unweighted arithmetic average first-day-of-the-month prices for the 12 months prior were $61.04/Bbl as compared to the market price for oil of $44.60/Bbl used for the December 31, 2008 reserves.

In 2008, the Company had net negative revisions of 1,684 MBoe. An estimated 461 MBoe reduction resulted from poor drilling results in the conventional Madison formation, including proved undeveloped locations offsetting the Madison formation drilling results. The remaining net 1,223 MBoe reduction is primarily related to the decrease in oil price, including 461 MBoe of proved undeveloped reserves at December 31, 2007, which did not have a positive PV-10 at the lower oil prices and were removed from the December 31, 2008 reserves. The index price for oil at December 31, 2008 decreased to $44.60/Bbl from $96.00/Bbl at December 31, 2007.

In 2007, the Company had net negative revisions of 35 MBoe. These revisions primarily resulted from adjustments to the performance projections and price assumptions used to calculate reserves at December 31, 2007 compared to those used in the initial evaluation of the properties acquired from Bill Barrett Corporation in June 2007.

F-30

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $96.00/Bbl for oil and $7.16/MMBtu for natural gas at December 31, 2007, and $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $61.04/Bbl for oil and $3.87/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The impact of the adoption of the FASB’s authoritative guidance on the SEC oil and gas reserve estimation final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves at December 31, 2009, 2008 and 2007.


	At Year Ended December 31,
	2009			2008			2007
	(In thousands)

Future cash inflows	$	664,480		$	85,678		$	365,725
Future production costs		(258,137	)		(54,885	)		(117,094	)
Future development costs		(120,212	)		(3,708	)		(20,792	)
Future income tax expense(1)		—			—			—

Future net cash flows		286,131			27,085			227,839
10% annual discount for estimated timing of cash flows		(152,601	)		(9,355	)		(106,032	)

Standardized measure of discounted future net cash flows	$	133,530		$	17,730		$	121,807


(1)		Does not include the effects of income taxes on future net revenues because as of December 31, 2009, 2008 and 2007, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to the company’s equity holders. Following its corporate reorganization, the Company will be a corporation and subject to U.S. federal and state income taxes. However, based on our history of losses since inception and expected deductible expenses in excess of earnings in 2010, we expect to incur net tax benefits; however, we will record a full valuation allowance for any associated tax assets that may result and therefore do not expect any net tax impact to be reported in the foreseeable future.

F-31

Oasis Petroleum LLC

Notes to Consolidated Financial Statements — (Continued)

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.


	2009			2008			2007(1)
	(In thousands)

January 1,	$	17,730		$	121,807		$	—

Net changes in prices and production costs		11,423			(48,986	)		38,863
Net changes in future development costs		1,998			210			(3,529	)
Sales of oil and natural gas, net		(25,254	)		(24,662	)		(9,634	)
Extensions		71,333			2,648			4,429
Discoveries		—			—			—
Purchases of reserves in place		36,809			—			78,965
Sales of reserves in place		(108	)		—			—
Revisions of previous quantity estimates		7,700			(48,260	)		(667	)
Previously estimated development costs incurred		—			746			6,476
Accretion of discount		3,352			12,181			3,948
Net change in income taxes		—			—			—
Changes in timing and other		8,547			2,046			2,956

December 31,	$	133,530		$	17,730		$	121,807


(1)		No beginning balance as the Company purchased the reserves from Bill Barrett Corporation in July 2007. Amounts represent changes from the date of acquisition to December 31, 2007.


14.	Quarterly Financial Data — Unaudited

The Company’s results of operations by quarter for the years ended 2009 and 2008 are as follows:


	For the Year Ended December 31, 2009:
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter(1)			Quarter
	(In thousands)

Revenues	$	3,216		$	6,036		$	11,046		$	17,457
Impairment of oil and gas properties		441			809			1,613			3,370
Operating loss		(6,091	)		(1,536	)		(329	)		(1,599	)
Net loss	$	(5,512	)	$	(5,883	)	$	(171	)	$	(3,643	)


	For the Year Ended December 31, 2008:
	First			Second			Third		Fourth
	Quarter			Quarter			Quarter		Quarter
	(In thousands)

Revenues	$	8,467		$	10,531		$	10,956	$	4,782
Impairment of oil and gas properties		259			92			884		45,882
Operating income (loss)		2,420			3,106			3,593		(48,934	)
Net income (loss)	$	(3,760	)	$	(25,361	)	$	23,287	$	(28,557	)


(1)		The Company recorded an adjustment to expense in the amount of $272,000 in the third quarter of 2009 associated with plugging and abandonment costs incurred in 2008.

F-32

Oasis Petroleum LLC

Consolidated Balance Sheet

(In thousands)


	March 31,			December 31,
	2010			2009
	(Unaudited)

Assets
Current assets
Cash and cash equivalents	$	2,610		$	40,562
Accounts receivable — oil and gas revenues		12,734			9,142
Accounts receivable — joint interest partners		2,302			1,250
Inventory		1,083			1,258
Prepaid expenses		77			134
Advances to joint interest partners		2,717			4,605
Derivative instruments		—			219

Total current assets		21,523			57,170

Property, plant and equipment
Oil and gas properties (successful efforts method)		277,225			243,350
Other properties		909			866
Less: accumulated depreciation, depletion, amortization and impairment		(68,390	)		(62,643	)

Total property, plant and equipment, net		209,744			181,573

Deferred costs and other assets		2,049			810

Total assets	$	233,316		$	239,553

Liabilities and members’ equity
Current liabilities
Accounts payable	$	3,757		$	1,577
Advances from joint interest partners		650			589
Production taxes and royalties payable		2,742			2,563
Accrued liabilities		19,041			18,038
Accrued interest payable		71			144
Derivative instruments		1,470			1,087

Total current liabilities		27,731			23,998

Long-term debt		23,000			35,000
Asset retirement obligations		6,794			6,511
Derivative instruments		1,874			2,085
Other liabilities		98			109

Total liabilities		59,497			67,703

Commitments and contingencies (Note 11)
Members’ equity
Capital contributions		235,000			235,000
Additional paid-in-capital		5,200			—
Accumulated loss		(66,381	)		(63,150	)

Total members’ equity		173,819			171,850

Total liabilities and members’ equity	$	233,316		$	239,553

The accompanying notes are an integral part of these consolidated financial statements.

F-33

Oasis Petroleum LLC

Consolidated Statement of Operations
(In thousands, except per share information)
(Unaudited)


	Three Months Ended
	March 31,
	2010			2009

Oil and gas revenues	$	20,068		$	3,216
Expenses
Lease operating expenses		2,977			1,807
Production taxes		1,910			268
Depreciation, depletion and amortization		5,849			2,528
Exploration expenses		18			(155	)
Rig termination		—			3,000
Impairment of oil and gas properties		3,077			441
Stock-based compensation expense		5,200			—
General and administrative expenses		3,516			1,418

Total expenses		22,547			9,307

Operating loss		(2,479	)		(6,091	)

Other income (expense)
Change in unrealized gain (loss) on derivative instruments		(391	)		(659	)
Realized gain (loss) on derivative instruments		(26	)		1,442
Interest expense		(338	)		(194	)
Other income (expense)		3			(10	)

Total other income (expense)		(752	)		579

Net loss	$	(3,231	)	$	(5,512	)

Pro forma loss per share:
Basic and diluted (Note 10)	$	(0.04	)	$	(0.06	)
Weighted averages shares outstanding:
Basic and diluted		92,000			92,000

The accompanying notes are an integral part of these consolidated financial statements.

F-34

Oasis Petroleum LLC

Consolidated Statement of Cash Flows
(In thousands)
(Unaudited)


	Three Months Ended
	March 31,
	2010			2009

Cash flows from operating activities:
Net loss	$	(3,231	)	$	(5,512	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		5,849			2,528
Impairment of oil and gas properties		3,077			441
Derivative instruments		417			(783	)
Non-cash stock-based compensation expense		5,200			—
Debt discount amortization and other		185			14
Working capital and other changes:
Change in accounts receivable		(5,263	)		(2,682	)
Change in inventory		269			—
Change in prepaid expenses		57			(103	)
Change in accounts payable and accrued liabilities		1,153			(3,375	)
Change in other liabilities		(11	)		(10	)

Net cash provided by (used in) operating activities		7,702			(9,482	)

Cash flows from investing activities:
Capital expenditures		(34,561	)		(14,147	)
Derivative settlements		(26	)		1,442
Advances to joint interest partners		1,888			355
Advances from joint interest partners		458			(159	)

Net cash used in investing activities		(32,241	)		(12,509	)

Cash flows from financing activities:
Proceeds from members’ contributions		—			34,000
Proceeds from issuance of debt		20,000			3,000
Reduction in debt		(32,000	)		(13,000	)
Debt issuance costs		(1,413	)		—

Net cash provided by (used in) financing activities		(13,413	)		24,000

Increase (decrease) in cash and cash equivalents		(37,952	)		2,009
Cash and cash equivalents
Beginning of period		40,562			1,570

End of period	$	2,610		$	3,579

Supplemental cash flow information:
Cash interest paid	$	237		$	160
Supplemental non-cash transactions:
Accrued capital expenditures	$	2,433		$	(5,358	)
Asset retirement obligations		283			77

The accompanying notes are an integral part of these consolidated financial statements.

F-36

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited)


1.	Organization and Operations of the Company

Organization

Oasis Petroleum LLC (“Oasis” or “Company”) was formed as a Delaware limited liability company on February 26, 2007 by certain members of the Company’s senior management team, through Oasis Petroleum Management LLC as described below, and private equity funds managed by EnCap Investments LLC (“EnCap”). EnCap, which was formed in 1988, provides private equity funding to independent oil and gas companies. As of March 31, 2010, EnCap was the majority holder and controlling member of the Company.

Nature of Business


2.	Summary of Significant Accounting Policies

For a summary of the Company’s significant accounting policies, refer to Note 1 of the audited consolidated financial statements for the year ended December 31, 2009, included elsewhere in this prospectus.

Basis of Presentation

The accompanying consolidated financial statements of the Company include the accounts of Oasis and its wholly owned subsidiaries OPI and OPNA. All significant intercompany transactions have been eliminated in consolidation. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included.

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus.

Recent Accounting Pronouncements

Subsequent Events — In May 2009, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance on subsequent events in order to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Particular importance has been placed on the period after the balance sheet date during which management should evaluate events or transactions that may occur, leading to recognition within the financial

F-37

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

statements or disclosure in the financial statements. This guidance is effective for financial statements issued for interim or annual reporting periods ending after June 15, 2009. In February 2010, the FASB amended this guidance to remove the requirement to disclose the date through which an entity has evaluated subsequent events for all SEC filers. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial position, cash flows or results of operations. See Note 12 — Subsequent Events.

Fair Value Measurements — In January 2010, the FASB issued authoritative guidance to update disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements, and are effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The adoption of this guidance for the period ended March 31, 2010 for Level 1 and Level 2 fair value measurements did not have an impact on the Company’s consolidated financial position, cash flows or results of operations. The guidance for Level 3 fair value measurements will require additional disclosures in future periods but will not impact the Company’s consolidated financial position, cash flows or results of operations.

Oil and Gas Reporting Requirements — In December 2008, the SEC released the final rule, “Modernization of Oil and Gas Reporting”, which adopted revisions to the SEC’s oil and gas reporting disclosure requirements. The disclosure requirements under this final rule require reporting of oil and gas reserves using the unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months rather than year-end prices, and the use of new technologies to determine proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are allowed, but not required, to disclose probable and possible reserves in SEC filings. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. In January 2010, the FASB issued authoritative guidance on oil and gas reserve estimation and disclosure, aligning their requirements with the SEC’s final rule. The Company implemented this new guidance for the year ended December 31, 2009 presented elsewhere in this prospectus.


3.	Inventory


	March 31,		December 31,
	2010		2009
	(In thousands)

Equipment and materials	$	328	$	588
Crude oil inventory		755		670

	$	1,083	$	1,258

F-38

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)


4.	Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment:


	March 31,			December 31,
	2010			2009
	(In thousands)

Proved oil and gas properties	$	228,042		$	195,546
Less: Accumulated depreciation, depletion, amortization and impairment		(68,035	)		(62,330	)

Proved oil and gas properties, net		160,007			133,216
Unproved oil and gas properties		49,183			47,804
Other property and equipment		909			866
Less: Accumulated depreciation		(355	)		(313	)

Other property and equipment, net		554			553

Total property, plant and equipment, net	$	209,744		$	181,573

As a result of expiring unproved leases, the Company recorded non-cash impairment charges of $3.1 million and $0.4 million for the three months ended March 31, 2010 and 2009, respectively.


5.	Fair Value Measurements

F-39

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards and options.


	At fair value as of March 31, 2010
	Level 1		Level 2		Level 3			Total
	(In thousands)

Assets (Liabilities):
Commodity Derivative Instruments (see Note 6)	$	—	$	—	$	(3,344	)	$	(3,344	)

Total Derivative Instruments	$	—	$	—	$	(3,344	)	$	(3,344	)


	At fair value as of December 31, 2009
	Level 1		Level 2		Level 3			Total
	(In thousands)

Assets (Liabilities):
Commodity Derivative Instruments (see Note 6)	$	—	$	—	$	(2,953	)	$	(2,953	)

Total Derivative Instruments	$	—	$	—	$	(2,953	)	$	(2,953	)

The Level 3 instruments presented in the tables above consist of crude oil swaps and collars. The Company utilizes the mark-to-market valuation reports provided by the counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculated the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s current cost of prime based borrowings (prime rate and associated margin effect). Based on these calculations, the Company recorded a downward adjustment to the fair value of its derivative instruments in the amount of $84,432 and $81,821 at March 31, 2010 and December 31, 2009, respectively.

F-40

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

The following table presents a reconciliation of the changes in fair value of the derivative instruments classified as Level 3 in the fair value hierarchy for the periods presented.


	2010			2009
	(In thousands)

Balance as of January 1	$	(2,953	)	$	4,090
Total gains or (losses) (realized or unrealized):
Included in earnings		(417	)		783
Included in other comprehensive income		—			—
Purchases, issuances and settlements		26			(1,442	)
Transfers in and out of level 3		—			—

Balance as of December 31	$	(3,344	)	$	3,431

Change in unrealized gains (losses) included in earnings relating to derivatives still held at March 31	$	(391	)	$	(659	)

At March 31, 2010, the Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The carrying amount of long-term debt reported in the Consolidated Balance Sheet at March 31, 2010 is $23.0 million, which approximates fair value due to the short-term maturity of the debt obligations (see Note 7 — Long-Term Debt).

Nonfinancial Assets and Liabilities

Asset Retirement Obligations — The carrying amount of the Company’s asset retirement obligations (“ARO”) in the Consolidated Balance Sheet at March 31, 2010 is $6.8 million (see Note 8 — Asset Retirement Obligations), which also approximates fair value as the Company determines the ARO by calculating the present value of estimated cash flows related to the liability based on the calculation of the estimated value. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs.

Impairment — The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Therefore, the Company’s proved oil and natural gas properties are measured at fair value on a non-recurring basis. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2010. For the three months ended March 31, 2009, the Company recorded a $10,000 impairment charge on its proved oil and natural gas properties. The 2009 impairment charge related to a dry hole, which had a fair value of zero.

F-41

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)


6.	Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of March 31, 2010, the Company utilized zero-cost collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production. As of December 31, 2009, the Company utilized both fixed-price swap agreements and zero-cost collar options.

All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their fair value (see Note 5 — Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value, both realized and unrealized, are recognized in the Other Income (Expense) section of the Consolidated Statement of Operations as a gain or loss on mark-to-market derivative contracts. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.

As of March 31, 2010, the Company had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges:


		Total Notional		Average		Average
Settlement	Derivative	Amount of Oil		Floor		Ceiling		Fair Value
Period	Instrument	(Barrels)		Price		Price		Asset (Liability)
								(In thousands)

2010	NYMEX Collar		422,686	$	69.15	$	90.38	$	(975	)
2011	NYMEX Collar		465,744	$	68.15	$	90.48		(2,167	)
2012	NYMEX Collar		38,418	$	68.07	$	90.56		(201	)

								$	(3,344	)

As of December 31, 2009, the Company had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges:


		Total Notional		Average		Average
Settlement	Derivative	Amount of Oil		Floor		Ceiling		Fixed		Fair Value
Period	Instrument	(Barrels)		Price		Price		Price		Asset (Liability)
										(In thousands)

2010	NYMEX Swap		11,163					$	72.25	$	(26	)
2010	NYMEX Collar		401,814	$	67.48	$	90.19				(841	)
2011	NYMEX Collar		186,764	$	61.49	$	82.23				(1,912	)
2012	NYMEX Collar		13,618	$	60.00	$	80.25				(174	)

										$	(2,953	)

F-42

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)


Fair Value of Derivative Instrument Assets (Liabilities)
		March 31,			December 31,
Instrument Type	Balance Sheet Location	2010			2009
		(In thousands)

Crude oil swap	Derivative Instruments — current assets	$	—		$	—
Crude oil collar	Derivative Instruments — current assets		—			219
Crude oil swap	Derivative Instruments — non-current asset		—			—
Crude oil collar	Derivative Instruments — non-current asset		—			—
Crude oil swap	Derivative Instruments — current liabilities		—			(26	)
Crude oil collar	Derivative Instruments — current liabilities		(1,470	)		(1,061	)
Crude oil collar	Derivative Instruments — non-current liabilities		(1,874	)		(2,085	)

	Total Derivative Instruments	$	(3,344	)	$	(2,953	)


		March 31,
	Income Statement Location	2010			2009
		(In thousands)

Derivative Contracts	Change in Unrealized Gain (Loss) on Derivative Instruments	$	(391	)	$	(659	)
Derivative Contracts	Realized Gain (Loss) on Derivative Instruments		(26	)		1,442

	Total Commodity Derivative Gain (Loss)	$	(417	)	$	783


7.	Long-Term Debt

The Company, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007, which was subsequently amended as of June 10, 2008, May 13, 2009 and June 23, 2009 (as amended, the “Credit Facility”). Under the Credit Facility, BNP Paribas, as administrative agent, and JPMorgan Chase Bank, as syndication agent, (collectively the “Lenders”) provide the Company with a senior secured revolving line of credit that is collateralized by all of the Company’s oil and gas properties.

On February 26, 2010, the Company entered into an agreement that amended and restated the existing Credit Facility (the “Amended Credit Facility”). The Amended Credit Facility increased the initial borrowing base to a maximum of $85 million, defined a future borrowing base of $70 million (the “Conforming Borrowing Base”), extended the maturity date to February 26, 2014, and added UBS Loan Finance LLC and Wells Fargo Bank as syndication agents. Borrowings under the Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports.

The Amended Credit Facility provides for semi-annual redeterminations on April 1 and October 1 of each year, commencing October 2, 2010. If the Company does not consummate an initial public stock offering before October 1, 2010, then the Borrowing Base shall equal the Conforming Borrowing Base on that date. The Conforming Borrowing Base is used as the denominator when calculating the utilization percentage of the Amended Credit Facility (the dollar amount of outstanding borrowings divided by the Conforming Borrowing Base).

F-43

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

and (2) whether the loan is a London Interbank Offered Rate (“LIBOR”) loan or a bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). The LIBOR and ABR loans bear their respective interest rates plus the applicable margin indicated in the following table:


	Applicable Margin			Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base	for LIBOR Loans			for ABR Loans

Less than .50 to 1		2.25	%		0.75	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.50	%		1.00	%
Greater than or equal to .75 to 1 but less than .85 to 1		2.75	%		1.25	%
Greater than .85 to 1 but less than or equal 1		3.00	%		1.50	%
Greater than 1 but less than 1.125		3.50	%		2.00	%
Greater than 1.125		4.00	%		2.50	%

An ABR loan does not have a set maturity date and may be repaid at any time upon the Company providing advance notification to the Lenders. Interest is paid quarterly for ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum loan term is six months for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms that are greater than three months in duration. At the end of a LIBOR loan term, the Amended Credit Facility allows the Company to elect to continue a LIBOR loan with the same or a differing loan term or convert the borrowing to an ABR loan. Because the Amended Credit Facility has a final maturity date of February 26, 2014, outstanding borrowings are classified as long-term debt in the Company’s Consolidated Balance Sheet at March 31, 2010.

For LIBOR loans, interest is payable at the maturity of the loan term. For ABR loans, interest is payable quarterly until such time the ABR loan balance is repaid or converted to a LIBOR loan.

The Amended Credit Facility contains covenants that include, among others:


	•	a prohibition against incurring debt, subject to permitted exceptions;

	•	a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;

	•	a prohibition against making investments, loans and advances, subject to permitted exceptions;

	•	restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;

	•	restrictions on merging and selling assets outside the ordinary course of business;

	•	restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;

	•	a provision limiting oil and natural gas hedging transactions to a volume not exceeding 80 percent (other than puts or floors not exceeding 100 percent) of anticipated production from proved developed producing reserves;

	•	a requirement that the Company not allow a ratio of Total Debt (as defined in the Amended Credit Facility) to consolidated EBITDAX (as defined in the Amended Credit Facility) to be greater than 4.0 to 1.0 for the four quarters ended on the last day of each quarter; and

F-44

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)


	•	a requirement that the Company maintain a Current Ratio of consolidated current assets (with exclusions as described in the Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Amended Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

The Amended Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Amended Credit Facility to be immediately due and payable.

As of March 31, 2010, borrowings under the Amended Credit Facility totaled $23.0 million and outstanding letters of credit issued under the Amended Credit Facility totaled $0.2 million, resulting in unused borrowing base capacity of $61.8 million. The weighted average interest rate incurred on the outstanding Amended Credit Facility borrowings was 10.6%. The Company was in compliance with all covenants of the Credit Facility and Amended Credit Facility during 2010.

Upon execution of the Amended Credit Facility, the Company recorded $1.4 million of deferred financing costs, which are being amortized over the term of the Amended Credit Facility and are included in deferred costs and other assets on the Consolidated Balance Sheet at March 31, 2010. The Company also wrote off $132,000 of unamortized deferred financing costs related to the Credit Facility, included in interest expense on the Consolidated Statement of Operations, for the three months ended March 31, 2010.


8.	Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the period:


	March 31,
	2010
	(In thousands)

Asset retirement obligation — beginning of period	$	6,511
Liabilities incurred through acquisitions		—
Liabilities incurred during period		181
Liabilities settled during period		—
Accretion expense during period		102
Revisions to estimates		—

Asset retirement obligation — end of period	$	6,794


9.	Stock-Based Compensation

In March 2010, the Company recorded a $5.2 million stock-based compensation expense associated with Oasis Petroleum Management LLC granting 1.0 million Class C Common Unit interests (“C Units”) to certain employees of the Company. The C Units were granted on March 24, 2010 to individuals who were employed by the Company as of February 1, 2010 and who were not executive officers or key employees with an existing capital investment in Oasis Petroleum Management LLC (“Oasis Petroleum Management LLC Capital Members”). All of the C Units vested immediately on the grant date, are non-voting and provide an opportunity for employees to participate in appreciation realized through a future sale of the Company, an initial public offering of the Company, and/or future sales or distributions of the Company’s shares indirectly held by Oasis Petroleum Management LLC.

Based on the characteristics of the C Units awarded to employees, the Company concluded that the C Units represented an equity-type award and accounted for the value of this award as if it had been awarded by the Company. The C Units shareholders are entitled to receive a portion of the distributions made to Oasis Petroleum Management LLC, but only after those future distributions have satisfied a complete return of the

F-45

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

capital investment previously made by the Oasis Petroleum Management LLC Capital Members, plus a specified return on their capital investment.

The C Units are membership interests in Oasis Petroleum Management LLC and not a direct interest in the Company. The C Units are non-transferable and have no voting power. Oasis Petroleum Management LLC has an interest in OAS Holdco, but neither Oasis Petroleum Management LLC nor its members have a controlling interest or controlling voting power in OAS Holdco. Oasis Petroleum Management LLC will distribute any cash or common stock it receives to its members based on membership interests and distribution percentages. Oasis Petroleum Management LLC will only make distributions if it first receives cash or common stock from distributions made at the election of OAS Holdco.

Under the FASB’s authoritative guidance for share-based payments, stock-based compensation cost is measured based on the calculated fair value of the award on the grant date. The expense is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. The Company used a fair-value-based method to determine the value of stock-based compensation awarded to its employees and recognized the entire grant date fair value of $5.2 million as stock-based compensation expense due to the immediate vesting of the awards and no future requisite service period required of the employees.

The Company used a probability weighted expected return method to evaluate the potential return to and associated fair value allocable to the C Unit shareholders using selected hypothetical future outcomes (continuing operations, private sale of the Company, and an initial public offering). Approximately 95% of the fair value allocable to the C Unit shareholders comes from the initial public offering (“IPO”) scenario. The IPO fair value of the C Units awarded to the Company’s employees was estimated on the date of the grant using the Black-Scholes option-pricing model with the assumptions described below, which represent Level 3 inputs (see Footnote 5 — Fair Value Measurements).

The exercise price of the option used in the option-pricing model was set equal to the maximum value of Oasis Petroleum Management LLC’s current capital investment in the Company as that value must be returned to Oasis Petroleum Management LLC Capital Members before distributions are made to the C Unit shareholders. Since the Company is not a public entity, it does not have historical stock trading data that can be used to compute volatilities associated with certain expected terms so the expected volatility value of 60% was estimated based on an average of volatilities of similar sized oil and gas companies with operations in the Williston Basin whose common stocks are publicly traded. Although the IPO is expected to occur in the near term there is no modeled distributable fair value that is allocable to the C Units as of March 31, 2010. The allocable fair value to the C Units occurs in an estimated timing of four years based on a future potential secondary offering or distribution of common stock of the Company. The OAS Holdco agreement between its members does require a complete distribution of all remaining shares held by OAS Holdco in the fourth year following the year of the IPO event. The 2.08% risk-free rate used in the pricing model is based on the U.S. Treasury yield for a government bond with a maturity equal to the time to liquidity of four years. The Company did not estimate forfeiture rates due to the immediate vesting of the award and did not estimate future dividend payments as it does not expect to declare or pay dividends in the foreseeable future.

Stock-based compensation expense recorded for the three months ended March 31, 2010 was $5.2 million. As the awards vested immediately, there was no unrecognized stock-based compensation expense as of March 31, 2010. No stock-based compensation expense was recorded for the three months ended March 31, 2009 as the Company had not historically issued stock-based compensation awards to its employees.


10.	Pro Forma Loss Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if outstanding common stock awards and stock options were exercised at the end of the period.

F-46

Oasis Petroleum LLC

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

The following is a calculation of the unaudited pro forma basic and diluted weighted-average shares outstanding for the three months ended March 31, 2010 and 2009:


	Three Months Ended
	March 31,
	2010		2009
	(In thousands)

Weighted average basic common shares outstanding		92,000		92,000
Effect of dilutive securities(1)		—		—

Weighted average diluted common shares outstanding		92,000		92,000


(1)		Because the Company reported an operating loss for the three months ended March 31, 2010 and 2009, no unvested stock awards and options were included in computing the pro forma loss per share because the effect would be anti-dilutive. In computing loss per share, no adjustments were made to reported net loss.


11.	Commitments and Contingencies

Lease Obligations — The Company has operating leases for its office space. The Company incurred lease rental expenses of $124,057 and $81,433 for the three months ended March 31, 2010 and 2009, respectively. In Note 10 to the audited consolidated financial statements for the year ended December 31, 2009, included elsewhere in this prospectus, the Company disclosed that it had future minimum annual rental commitments under noncancelable leases for 2010 of $451,000. As of March 31, 2010, the outstanding annual rental commitment for the remainder of 2010 is $316,000.

Drilling Contracts — On January 27, 2010, the Company entered into a new drilling rig contract. In the event of early contract termination under this new contract, the Company is obligated to pay a daily shortfall rate of $8,000 per day for the days remaining between the date of termination and June 15, 2010, the end of the primary contract term. On February 22, 2010, the Company extended the term of this contract by one month to July 15, 2010. All other rates, terms and conditions of the rig contract remained unchanged. On March 25, 2010, the Company entered into an additional new drilling rig contract. In the event of early contract termination under this new contract, the Company is obligated to pay a daily shortfall rate of $10,000 per day for the days remaining between the date of termination and April 25, 2011, the end of the primary contract term.


12.	Subsequent Events

The Company has evaluated the period after the balance sheet date up through June 2, 2010, the date the consolidated financial statements were issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

New Drilling Rig Contracts — On May 3, 2010, the Company entered into a new drilling rig contract to drill two wells. In the event of early contract termination under this new contract, the Company is obligated to pay a lump sum of $147,000 for each well not drilled. On the execution date of the contract, the Company had begun operations on the first well, resulting in a maximum exposure of $147,000 if the second well is not drilled.

F-47

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Oasis Petroleum Inc.:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Oasis Petroleum Inc. at February 25, 2010 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of Oasis Petroleum Inc.’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 4, 2010

F-48

Report of Independent Registered Public Accounting Firm

To the Board of Managers of Oasis Petroleum LLC:

In our opinion, the accompanying statement of revenues and direct operating expenses presents fairly, in all material respects, the revenues and direct operating expenses of the Bill Barrett Corporation Acquisition Properties described in Note 1 for the six months ended June 30, 2007, in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of Oasis Petroleum LLC’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

The accompanying financial statement reflects the revenues and direct operating expenses of the Bill Barrett Corporation Acquisition Properties as described in Note 1 and is not intended to be a complete presentation of the financial position, results of operations, or cash flows of the Bill Barrett Corporation Acquisition Properties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 4, 2010

F-51

Bill Barrett Corporation Acquisition Properties (as Predecessor)

Notes to Statement of Revenues and Direct Operating Expenses


1.	Properties and Basis of Presentation

The accompanying statement represents the interest in the revenues and direct operating expenses of the oil and natural gas producing properties acquired by Oasis Petroleum LLC (the “Company”) from Bill Barrett Corporation (“Barrett”) in June 2007, which constitutes the accounting predecessor to the Company. The purchase transaction had an effective date of May 1, 2007 and the Company paid $83.5 million for the properties, subject to customary purchase accounting adjustments. The properties are referred to herein as the “Barrett Acquisition Properties”. The Barrett Acquisition Properties are located in the Williston Basin of Montana and North Dakota. The Company closed the acquisition on June 22, 2007 and began managing the properties effective July 1, 2007.

The statement of revenues and direct operating expenses has been derived from Barrett’s historical financial records. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Barrett Acquisition Properties. Oil, gas and condensate revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease and well repairs, production taxes, gathering and transportation, maintenance, utilities, payroll and other direct operating expenses. Production taxes for the six months ended June 30, 2007 totaled $907,000.

The statement of revenues and direct operating expenses is not indicative of the financial condition or results of operations of the Barrett Acquisition Properties going forward due to both changes in the business and the omission of various operating expenses. Since the acquisition of these properties, the Company has focused production and reserve growth almost exclusively on the unconventional Bakken and Three Fork formations, and as such, production and reserves, as well as costs and expenses, associated with the Barrett Acquisition Properties as operated by the Company differ significantly from those characteristics when such properties were operated by Barrett. During the period presented, the Barrett Acquisition Properties were not accounted for by Barrett as a separate entity. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the Barrett Acquisition Properties.


2.	Omitted Financial Information

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on an individual property basis, nor is it practicable to obtain such information in these circumstances. Historically, no allocation of general and administrative, interest, corporate taxes, accretion of asset retirement obligations, and depreciation, depletion and amortization was made to the Barrett Acquisition Properties. Accordingly, the statement of revenues and direct operating expenses is presented in lieu of the financial statements required under Rule 3-01 and Rule 3-02 of the Securities and Exchange Commission’s Regulation S-X.


3.	Supplemental Oil and Gas Reserve Information — Unaudited

Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited

The following tables summarize the net ownership interests in estimated quantities of proved and proved developed oil and natural gas reserves of the Barrett Acquisition Properties at January 1, 2007 and June 30, 2007, estimated by the Company’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the six months ended June 30, 2007.

F-53

Bill Barrett Corporation Acquisition Properties (as Predecessor)

Notes to Statement of Revenues and Direct Operating Expenses — (Continued)

economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.


	Natural Gas			Oil
	(MMcf)			(MBbls)

Proved reserves at January 1, 2007		1,202			4,172
Production through June 30, 2007		(69	)		(190	)

Proved reserves at June 30, 2007		1,133			3,982


	Natural Gas		Oil
	(MMcf)		(MBbls)

Proved developed reserves at January 1, 2007		989		3,287
Proved developed reserves at June 30, 2007		920		3,097


	Natural Gas		Oil
	(MMcf)		(MBbls)

Proved undeveloped reserves at January 1, 2007		213		885
Proved undeveloped reserves at June 30, 2007		213		885

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited

The following tables sets forth the computation of the standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved reserves and the changes in such cash flows of the Barrett Acquisition Properties in accordance with the Financial Accounting Standards Board’s (“FASB”) authoritative guidance related to disclosures about oil and gas producing activities. The Standardized Measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, estimated future income taxes (if applicable) and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisitions, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on period-end prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. In accordance with the FASB’s authoritative guidance, a discount rate of 10% is applied to the annual future net cash flows.

In calculating the Standardized Measure, future net cash inflows were estimated by using period-end oil and natural gas prices with the estimated future production of period-end proved reserves and assume continuation of existing economic conditions. The index prices used for the June 30, 2007 Standardized Measure calculations were $70.68 per barrel of oil and $6.36 per MMBtu of natural gas. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs resulting in net cash flow before tax. Future income tax expense was not considered as Oasis Petroleum LLC and the Barrett Acquisition Properties are not tax-paying entities.

F-54

Bill Barrett Corporation Acquisition Properties (as Predecessor)

Notes to Statement of Revenues and Direct Operating Expenses — (Continued)

The Standardized Measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.


	June 30, 2007
	(In thousands)

Future cash inflows	$	261,296
Future production costs		(97,444	)
Future development costs		(20,741	)

Future net cash flows		143,111
10% annual discount for estimating timing of cash flows		(64,997	)

Standardized Measure of discounted net cash flows relating to proved oil and gas reserves	$	78,114


Changes in the Standardized Measure (in thousands) of the Barrett Acquisition Properties are as follows:
January 1, 2007	$	65,434
Changes in prices and costs		16,473
Accretion of discount		3,403
Sales of oil and gas, net of costs		(7,196	)

June 30, 2007	$	78,114

F-55

Report of Independent Registered Public Accounting Firm

To the Board of Managers of Oasis Petroleum LLC:

In our opinion, the accompanying statement of revenues and direct operating expenses presents fairly, in all material respects, the revenues and direct operating expenses of the Kerogen Acquisition Properties described in Note 1 for the year ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of Oasis Petroleum LLC’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

The accompanying financial statement reflects the revenues and direct operating expenses of the Kerogen Acquisition Properties as described in Note 1 and is not intended to be a complete presentation of the financial position, results of operations, or cash flows of the Kerogen Acquisition Properties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 4, 2010

F-56

Kerogen Acquisition Properties

Notes to Statement of Revenues and Direct Operating Expenses


1.	Properties and Basis of Presentation

The accompanying statement represents the interest in the revenue and direct operating expenses of the oil and natural gas producing properties acquired by Oasis Petroleum LLC (the “Company”) from Kerogen Resources, Inc. (“Kerogen”) on June 15, 2009 for $27.1 million, subject to customary purchase accounting adjustments. The properties are referred to herein as the “Kerogen Acquisition Properties”.

The statement of revenues and direct operating expenses for the year ended December 31, 2008 has been derived from Kerogen’s historical financial records. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Kerogen Acquisition Properties. Oil, gas and condensate revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease and well repairs, production taxes, gathering and transportation, maintenance, utilities, payroll and other direct operating expenses. Production taxes for the year ended December 31, 2008 were $1.3 million.

The statement of revenues and direct operating expenses is not indicative of the financial condition or results of operations of the Kerogen Acquisition Properties going forward due to both changes in the business and the omission of various operating expenses. Production and reserves, as well as costs and expenses, associated with the Kerogen Acquisition Properties as operated by the Company differ significantly from those characteristics when such properties were operated by Kerogen. During the periods presented, the Kerogen Acquisition Properties were not accounted for by Kerogen as a separate entity. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the Kerogen Acquisition Properties.

The accompanying statement of revenues and direct operating expenses for the three months ended March 31, 2008 and 2009 is unaudited. The unaudited interim statements of revenues and direct operating expenses have been derived from Kerogen’s historical financial records and prepared on the same basis as the statement of revenues and direct operating expenses for the year ended December 31, 2008. In the opinion of management, such unaudited interim statements reflect all adjustments necessary to fairly present the Kerogen Acquisition Properties’ excess of revenue over direct operating expenses for the three months ended March 31, 2008 and 2009.


2.	Omitted Financial Information

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on an individual property basis, nor is it practicable to obtain such information in these circumstances. Historically, no allocation of general and administrative, interest, corporate taxes, accretion of asset retirement obligations, depreciation, depletion and amortization was made to the Kerogen Acquisition Properties. Accordingly, the statements of revenues and direct operating expenses are presented in lieu of the financial statements required under Rule 3-01 and Rule 3-02 of the Securities and Exchange Commission’s Regulation S-X.


3.	Supplemental Oil and Gas Reserve Information (Unaudited)

Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited

The following tables summarize the net ownership interests in estimated quantities of proved and proved developed oil and natural gas reserves of the Kerogen Acquisition Properties at January 1, 2008 and December 31, 2008, estimated by the Company’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the year.

F-58

Kerogen Acquisition Properties

Notes to Statement of Revenues and Direct Operating Expenses — (Continued)

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate was made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.


	Natural Gas			Oil
	(MMcf)			(MBbls)

Proved reserves at January 1, 2008		1,825			1,557
Production in 2008		(299	)		(172	)

Proved reserves at December 31, 2008		1,526			1,385


	Natural Gas		Oil
	(MMcf)		(MBbls)

Proved developed reserves at January 1, 2008		1,588		1,079
Proved developed reserves at December 31, 2008		1,289		907


	Natural Gas		Oil
	(MMcf)		(MBbls)

Proved undeveloped reserves at January 1, 2008		237		478
Proved undeveloped reserves at December 31, 2008		237		478

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves — Unaudited

The following tables set forth the computation of the standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved reserves and the changes in such cash flows of the Kerogen Acquisition Properties in accordance with the Financial Accounting Standards Board’s (“FASB”) authoritative guidance related to disclosures about oil and gas producing activities. The Standardized Measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, estimated future income taxes (if applicable) and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on period-end prices and any fixed and determinable future price changes provided by contractual arrangements in existence at year end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. In accordance with the FASB’s authoritative guidance, a discount rate of 10% is applied to the annual future net cash flows.

In calculating the Standardized Measure, future net cash inflows were estimated by using year-end oil and natural gas prices with the estimated future production of year-end proved reserves and assume continuation of existing economic conditions. The index prices used for the December 31, 2008 Standardized Measure calculations were $44.60 per barrel of oil and $5.63 per MMBtu of natural gas. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs resulting in net cash flow before tax. Future income tax expense was not considered as Oasis Petroleum LLC and the Kerogen Acquisition Properties are not tax paying entities.

F-59

Kerogen Acquisition Properties

Notes to Statement of Revenues and Direct Operating Expenses — (Continued)


	December 31,
	2008
	(In thousands)

Future cash inflows	$	63,010
Future production costs		(34,433	)
Future development costs		(6,853	)

Future net cash flows		21,724
10% annual discount for estimating timing of cash flows		(7,756	)

Standardized measure of discounted net cash flows relating to proved oil and gas reserves	$	13,968

Changes in the Standardized Measure (in thousands) of the Kerogen Acquisition Properties are as follows:


January 1, 2008	$	55,161
Changes in prices and costs		(29,353	)
Accretion of discount		1,278
Sales of oil and gas, net of costs		(13,118	)

December 31, 2008	$	13,968

F-60

Kerogen Acquisition Properties

Unaudited Pro Forma Financial Information

On June 15, 2009, Oasis Petroleum LLC (the “Company”) acquired interests in oil and gas properties primarily in the East Nesson area of the Williston Basin from Kerogen Resources, Inc. (the “Kerogen Acquisition Properties”) for $27.1 million. The purchase price was paid using proceeds from a capital contribution from the members of Oasis Petroleum Management LLC, a wholly owned subsidiary of the Company. In addition to acquiring the interests in the East Nesson area, the Company also acquired non-operated interests in the Sanish project area.

The following unaudited pro forma statement of operations shows the pro forma effect of the acquisition of the Kerogen Acquisition Properties. The Company’s historical results include the results from the acquisition of the Kerogen Acquisition Properties beginning on June 15, 2009. A pro forma balance sheet has not been presented since the acquisition has been reflected in the Company’s December 31, 2009 consolidated balance sheet included elsewhere in this prospectus. The unaudited pro forma statement of operations for the year ended December 31, 2009 presented below was prepared as if the acquisition occurred on January 1, 2009.

The unaudited pro forma statement of operations does not reflect the pro forma effect of any of the Company’s other recent acquisitions discussed in this prospectus as they were not deemed significant, nor does this statement reflect the transactions described under “Corporate Reorganization.” The Company has conducted its operations as a limited liability company with substantially all earnings taxed at the stockholder level. Following its corporate reorganization, the Company will be subject to Subchapter C of the Internal Revenue Code, and, as a result, will become taxable as a corporation and subject to U.S. federal and state income taxes. No pro forma tax benefit has been reflected as management believes that it is more likely than not that such benefit would not be realized in the future.

Management believes that the assumptions used to prepare the unaudited pro forma statement of operations provide a reasonable basis for presenting the significant effects directly attributable to the transaction. The following unaudited pro forma statement of operations does not purport to represent what the Company’s results of operations would have been if the Kerogen property acquisition had occurred on January 1, 2009 and should be read in conjunction with the Company’s historical consolidated financial statements and the notes to those financial statements and the accompanying statements of revenues and direct operating expenses for the Kerogen Acquisition Properties included elsewhere in this prospectus. The unaudited pro forma statement of operations presented below is also not indicative of the financial condition or results of operations of the Company going forward due to both changes in the business and the omission of various operating expenses. Production and reserves, as well as costs and expenses, associated with the Kerogen Acquisition Properties as operated by the Company differ significantly from those characteristics when such properties were operated by Kerogen Resources, Inc. During the period presented, the Kerogen Acquisition Properties were not accounted for by Kerogen Resources as a separate entity. As such, certain

F-61

Kerogen Acquisition Properties

Unaudited Pro Forma Financial Information — (Continued)

costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the Kerogen Acquisition Properties.


	For the Year Ended December 31, 2009
				Kerogen Acquisition
				Properties Pro
	Oasis Historical			Forma Adjustments			Oasis Pro Forma
	(In thousands)

Oil and gas revenues	$	37,755		$	4,244	(1)	$	41,999

Expenses
Lease operating expenses		8,691			1,583	(1)		10,274
Production taxes		3,810			350	(1)		4,160
Depreciation, depletion and amortization		16,670			2,563	(2)		19,233
Exploration costs		1,019			—			1,019
Rig termination		3,000			—			3,000
Impairment of oil and gas properties		6,233			—			6,233
Gain on sale of properties		(1,455	)		—			(1,455	)
General and administrative		9,342			—			9,342

Total expenses		47,310			4,496			51,806

Operating loss		(9,555	)		(252	)		(9,807	)

Other income (expense)
Change in unrealized gain (loss) on derivative instruments		(7,043	)		—			(7,043	)
Realized gain (loss) on derivative instruments		2,296			—			2,296
Interest expense		(912	)		—			(912	)
Other income (expense)		5			—			5

Total other income (expense)		(5,654	)		—			(5,654	)

Net loss	$	(15,209	)	$	(252	)	$	(15,461	)

The following adjustments were made in the preparation of the unaudited pro forma consolidated financial information presented above:


(1)		Adjustments to recognize revenues and direct operating expenses of the Kerogen Acquisition Properties for the period from January 1, 2009 through June 14, 2009, the period for which financial results are not included in the historical results of the Company.

(2)		Adjustment to recognize additional depreciation, depletion and amortization on the Kerogen Acquisition Properties as if the acquisition had taken place on January 1, 2009, using the unit-of-production method under the successful efforts method of accounting. This adjustment also includes the additional accretion expense on the asset retirement obligations attributable to the Kerogen Acquisition Properties as if the acquisition had taken place on January 1, 2009.

F-62

GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms defined in this section are used throughout this prospectus:

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf.” One billion cubic feet of natural gas.

“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.

“Development well.” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.

“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Infill wells.” Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

“MBbl.” One thousand barrels of crude oil, condensate or natural gas liquids.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBbl.” One million barrels of crude oil, condensate or natural gas liquids.

A-1

“MMBoe.” One million barrels of oil equivalent.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“NYMEX.” The New York Mercantile Exchange.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.”

Under SEC rules for fiscal years ending on or after December 31, 2009, proved reserves are defined as:

Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Under SEC rules for fiscal years ending prior to December 31, 2009, proved reserves are defined as:

The estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs

A-2

under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

“Proved undeveloped reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“Reasonable certainty.” A high degree of confidence.

“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserves.” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

A-3


	Page

Oasis Petroleum LLC
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheet at December 31, 2009 and 2008		F-3
Consolidated Statement of Operations for the Years Ended December 31, 2009, 2008 and for the Period from February 26, 2007 (Inception) to December 31, 2007		F-4
Consolidated Statement of Changes in Members’ Equity for the Years Ended December 31, 2009, 2008 and for the Period from February 26, 2007 (Inception) to December 31, 2007		F-5
Consolidated Statement of Cash Flows for the Years Ended December 31, 2009, 2008 and for the Period from February 26, 2007 (Inception) to December 31, 2007		F-6
Notes to Consolidated Financial Statements		F-7
Oasis Petroleum LLC
Consolidated Balance Sheet at March 31, 2010 (unaudited) and December 31, 2009 (audited)		F-33
Consolidated Statement of Operations for the Three Months Ended March 31, 2010 and 2009 (unaudited)		F-34
Consolidated Statement of Changes in Members’ Equity for the Three Months Ended March 31, 2010 (unaudited)		F-35
Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2010 and 2009 (unaudited)		F-36
Notes to Consolidated Financial Statements (unaudited)		F-37
Oasis Petroleum Inc.
Report of Independent Registered Public Accounting Firm		F-48
Balance Sheet at February 25, 2010 (audited) and March 31, 2010 (unaudited)		F-49
Notes to Balance Sheet		F-50
Bill Barrett Corporation Acquisition Properties (as Predecessor)
Report of Independent Registered Public Accounting Firm		F-51
Statement of Revenues and Direct Operating Expenses for the Six Months Ended June 30, 2007		F-52
Notes to Statement of Revenues and Direct Operating Expenses		F-53
Kerogen Acquisition Properties
Report of Independent Registered Public Accounting Firm		F-56
Statement of Revenues and Direct Operating Expenses for the Year Ended December 31, 2008 (audited) and for the Three Months Ended March 31, 2009 and 2008 (unaudited)		F-57
Notes to Statements of Revenues and Direct Operating Expenses		F-58
Kerogen Acquisition Properties
Unaudited Pro Forma Financial Information		F-61


	(In thousands)

Members’ Equity, February 26, 2007 (Inception)	$	—
Capital Contributions		49,900
Net Loss		(13,550	)

Members’ Equity, December 31, 2007		36,350

Capital Contributions		80,500
Net Loss		(34,391	)

Members’ Equity, December 31, 2008		82,459

Capital Contributions		104,600
Net Loss		(15,209	)

Members’ Equity, December 31, 2009	$	171,850


	February 25,		March 31,
	2010		2010
			(Unaudited)
Assets
Cash	$	10	$	10

Total assets	$	10	$	10

Shareholders’ equity
Common stock, $0.01 par value; authorized 1,000 shares; 1,000 issued and outstanding at February 25, 2010	$	10	$	10

Total shareholders’ equity	$	10	$	10


	Six Months
	Ended
	June 30, 2007
	(In thousands)

Oil and gas revenues	$	10,686
Direct operating expenses		3,490

Excess of revenues over direct operating expenses	$	7,196